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Table of Contents
Index to Financial Statements
As filed with the Securities and Exchange Commission on October 18, 2011
Registration No. 333-175395
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Amendment No. 3
to
FORM S-1
Chesapeake Granite Wash Trust
Amendment No. 3
to
FORM S-3
Chesapeake Energy Corporation
(Exact name of co-registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Number)
45-6355635
(I.R.S. Employer Identification No.)
(Exact name of co-registrant as specified in its charter)
Oklahoma
(State or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Number)
73-1395733
(I.R.S. Employer Identification No.)
919 Congress Avenue, Suite 500
Austin, Texas 78701
(512) 236-6599
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
(405) 848-8000
(Address, including zip code, and telephone number, including
area code, of registrant’s principal executive offices)
(Address, including zip code, and telephone number, including area code, of registrant’s
principal executive offices)
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue, Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
Jennifer M. Grigsby
Senior Vice President, Treasurer
and Corporate Secretary
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
(405) 848-8000
(Name, address, including zip code, and telephone number, including area code, of agent for
service)
(Name, address, including zip code, and telephone number, including area code, of agent for
service)
Copies to:
Michael S. Telle
Bracewell & Giuliani LLP
711 Louisiana Street, Suite 2300
Houston, Texas 77002-2770
(713) 221-1327
(713) 221-2113 (fax)
Joshua Davidson
Hillary H. Holmes
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002-4995
(713) 229-1234
(713) 229-1522 (fax)
Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933,
check the following box: 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the
Securities Act registration statement number of the earlier effective registration statement for the same offering. 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same offering. 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same offering. 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Chesapeake Granite Wash Trust
Large accelerated filer

Accelerated filer

Non-accelerated filer
 (Do not check if a smaller reporting company)
Smaller reporting company


 (Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company


Chesapeake Energy Corporation
Large accelerated filer
Non-accelerated filer
The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall
file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the
Securities Act, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
Table of Contents
Index to Financial Statements
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and
Exchange Commission is effective. This prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities, in any state where the
offer or sale is not permitted.
PROSPECTUS (Subject to Completion)
Issued October 18, 2011
22,875,000 Common Units
Chesapeake Granite Wash Trust
REPRESENTING BENEFICIAL INTERESTS
This is an initial public offering of common units representing beneficial interests in Chesapeake Granite Wash Trust. The trust is selling all of the common units offered hereby. Chesapeake Energy
Corporation (“Chesapeake”) will convey to the trust certain royalty interests in exchange for common and subordinated units collectively representing a 50% beneficial interest in the trust (without giving
effect to the exercise of the underwriters’ option to purchase additional units), as well as all of the net proceeds of this offering.
Prior to this offering, there has been no public market for the common units. Chesapeake anticipates that the initial public offering price will be between $19.00 and $21.00 per common unit. The common
units have been approved for listing on the New York Stock Exchange under the symbol “CHKR.”
The Trust Units. Trust units, consisting of common and subordinated units, are units representing undivided beneficial interests in the property of the trust. They do not represent any interest in Chesapeake.
The Trust. The trust will own term and perpetual royalty interests in oil, natural gas liquids and natural gas properties leased by Chesapeake in the Colony Granite Wash play, located in Washita County,
Oklahoma. These royalty interests will entitle the trust to receive, after the deduction of post-production expenses and taxes, (a) 90% of the proceeds attributable to Chesapeake’s net revenue interest in the
sale of production from 69 horizontal producing wells and (b) 50% of the proceeds attributable to Chesapeake’s net revenue interest in the sale of production from 118 horizontal development wells to be
drilled within an Area of Mutual Interest consisting of approximately 45,400 gross acres (28,700 net acres) held by Chesapeake. The number of wells required to be drilled may increase or decrease in
proportion to Chesapeake’s actual net revenue interest in each well and other factors described herein. The trust will not be responsible for any costs related to the drilling of these wells. The trust will be
treated as a partnership for U.S. federal income tax purposes.
The Trust Unitholders. As a trust unitholder, you will receive quarterly distributions of cash from the proceeds that the trust receives from Chesapeake’s sale of oil, natural gas liquids and natural gas from
properties subject to the royalty interests to be held by the trust. The amount of the distributions will be impacted by oil and natural gas liquids hedges to which the trust will be a party. For information on
target distributions and related matters pertinent to trust unitholders, including Chesapeake’s right to receive incentive distributions and ownership of subordinated units, please see “Target Distributions
and Subordination and Incentive Thresholds” beginning on page 50.
Investing in the common units involves a high degree of risk. See “Risk Factors” beginning on page 20.
These risks include the following:
•
Drilling for and producing oil, natural gas liquids and natural gas involves many risks that could delay the anticipated drilling schedule for the development wells and adversely affect
future production, which could decrease cash distributions to unitholders.
•
Price fluctuations for oil, natural gas liquids and natural gas could reduce proceeds to the trust and decrease cash distributions to unitholders.
•
Actual reserves and future production may be less than current estimates.
•
Estimates of target distributions to unitholders are based on assumptions that are inherently subjective and are subject to significant risks and uncertainties that could cause actual
distributions to differ materially from estimates.
Hedging arrangements will cover only a portion of the expected production attributable to the trust, and such arrangements will limit the trust’s ability to benefit from commodity price
increases for hedged volumes above the corresponding hedge price.
If the trust were treated as a corporation for U.S. federal income tax purposes, then its cash available for distribution to unitholders would be substantially reduced.
•
•
•
•
If the IRS contests the tax positions the trust takes, the value of the trust units may be adversely affected, the cost of any IRS contest will reduce the trust’s cash available for distribution
and income, gain, loss and deduction may be reallocated among trust unitholders.
The tax treatment of an investment in trust units could be affected by potential legislative changes, possibly on a retroactive basis.
PRICE $
A COMMON UNIT
Price to Public
Per Common Unit
Total
(1)
$
$
Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering, or approximately $
Associates, Inc.
Underwriting
Discounts and
Commissions (1)
$
$
Proceeds to
Trust (2)
$
$
million, payable to Morgan Stanley & Co. LLC and Raymond James &
(2)
The trust will deliver all of the proceeds it receives in this offering to a wholly owned subsidiary of Chesapeake.
The trust has granted the underwriters an option to purchase up to an additional 3,431,250 common units.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any
representation to the contrary is a criminal offense.
The underwriters expect to deliver the common units to purchasers on
, 2011.
MORGAN STANLEY
Deutsche Bank Securities
, 2011
RAYMOND JAMES
Goldman, Sachs & Co.
Wells Fargo Securities
Table of Contents
Index to Financial Statements
Table of Contents
Index to Financial Statements
TABLE OF CONTENTS
IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS
SUMMARY
RISK FACTORS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
USE OF PROCEEDS
CHESAPEAKE ENERGY CORPORATION
THE TRUST
TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
THE UNDERLYING PROPERTIES
DESCRIPTION OF THE ROYALTY INTERESTS
DESCRIPTION OF THE TRUST AGREEMENT
DESCRIPTION OF THE TRUST UNITS
TRUST UNITS ELIGIBLE FOR FUTURE SALE
U.S. FEDERAL INCOME TAX CONSIDERATIONS
STATE TAX CONSIDERATIONS
ERISA CONSIDERATIONS
UNDERWRITING
LEGAL MATTERS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND TERMS RELATED TO THE TRUST
FINANCIAL STATEMENTS
ANNEX A: SUMMARY OF RESERVE REPORTS
ANNEX B: QUARTERLY TARGET DISTRIBUTIONS
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1
20
41
42
43
44
50
64
78
83
89
93
95
111
112
113
119
119
119
121
F-1
A-1
B-1
IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS
You should rely only on the information contained in this prospectus or in any free writing prospectus the trust may authorize to be delivered to you.
Until
, 2011 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the common units, whether
or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
The trust and Chesapeake have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides
you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the common
units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date
other than the date on the front of this document unless otherwise specified herein. The trust’s and Chesapeake’s business, financial condition, results of operations and
prospects may have changed since such date.
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SUMMARY
This summary provides a brief overview of information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire
prospectus carefully, including the risk factors, the summary reserve reports and the financial statements and notes to those statements. Definitions for certain terms
relating to the oil and natural gas business can be found in “Glossary of Certain Oil and Natural Gas Terms and Terms Related to the Trust” beginning on page 121.
Ryder Scott Company, L.P., referred to in this prospectus as “Ryder Scott,” an independent engineering firm, provided the estimates of proved oil, natural gas liquids
and natural gas reserves as of June 30, 2011 included in this prospectus. These estimates are contained in summaries prepared by Ryder Scott of its reserve reports for
(a) the properties held by Chesapeake from which the royalty interests will be conveyed to the trust and (b) the royalty interests to be held by the trust. These reports
are included as Annex A to this prospectus and are referred to in this prospectus as the “reserve reports.” References to “Chesapeake” in this prospectus are to
Chesapeake Energy Corporation and, where the context requires, its subsidiaries. The royalty interests to be held by the trust are sometimes referred to herein as the
“trust properties.” Unless otherwise indicated, all information in this prospectus assumes an initial public offering price of $20.00 per common unit (the midpoint of
the price range set forth on the cover page of this prospectus) and no exercise of the underwriters’ option to purchase additional common units.
Chesapeake Granite Wash Trust
Chesapeake Granite Wash Trust is a Delaware statutory trust formed in June 2011 to own (a) royalty interests to be conveyed to the trust by Chesapeake in 69
existing horizontal wells in the Colony Granite Wash play located in Washita County in western Oklahoma (the “Producing Wells”), and (b) royalty interests in 118
horizontal development wells (calculated as described under “—The Development Wells” beginning on page 3) to be drilled exclusively in the Colony Granite Wash
(the “Development Wells”) on properties within an Area of Mutual Interest (as such area may be extended as described below, the “AMI”). The AMI is limited to only
the Colony Granite Wash formation and is depicted by the area identified in the inside front cover of this prospectus, currently consisting of approximately 45,400 gross
acres (28,700 net acres) held by Chesapeake. The Colony Granite Wash is a formation encountered at depths between approximately 11,500 feet and 13,000 feet that
lies between the top of the Des Moines formation (or top of Colony Granite Wash ‘A’) and the top of the Prue formation (or base of Colony Granite Wash ‘C’).
Chesapeake intends to drill, or cause to be drilled, the Development Wells from proved undeveloped (“PUD”) drilling locations in the AMI by June 30, 2015 and is
obligated to complete such drilling by June 30, 2016.
The royalty interests will be conveyed from Chesapeake’s interest in the Producing Wells and the Development Wells (the “Underlying Properties”) effective as
of July 1, 2011. As of July 1, 2011, 64 of the Producing Wells were producing from the Colony Granite Wash and the remaining five Producing Wells had been drilled
and were awaiting completion. As of October 1, 2011, all of the Producing Wells were completed and producing. The royalty interest in the Producing Wells (the “PDP
Royalty Interest”) entitles the trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production expenses and
any applicable taxes) from the sale of production of oil, natural gas liquids and natural gas attributable to Chesapeake’s net revenue interest in the Producing Wells. The
royalty interest in the Development Wells (the “Development Royalty Interest”) entitles the trust to receive 50% of the proceeds (exclusive of any production or
development costs but after deducting post-production expenses and any applicable taxes) from the sale of oil, natural gas liquids and natural gas production attributable
to Chesapeake’s net revenue interest in the Development Wells.
As of June 30, 2011 and after giving effect to the conveyance of the PDP Royalty Interest and the Development Royalty Interest to the trust, the total reserves
estimated to be attributable to the trust were 44.3 mmboe (47.0% oil and natural gas liquids by volume). This amount includes 18.6 mmboe attributable to the PDP
Royalty Interest and 25.7 mmboe attributable to the Development Royalty Interest.
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Index to Financial Statements
Generally, the percentage of production proceeds to be received by the trust with respect to a well will equal the product of (a) the percentage of proceeds to
which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the Development Wells) multiplied by (b) Chesapeake’s net
revenue interest in the well. Chesapeake on average owns a 52.8% net revenue interest in the Producing Wells. Therefore, the trust will have an average 47.5% net
revenue interest in the Producing Wells. Chesapeake on average owns a 52.0% net revenue interest in the properties on which it expects to drill the Development Wells,
and based on this net revenue interest, the trust would have an average 26.0% net revenue interest in the Development Wells. Chesapeake’s actual net revenue interest
in any particular Producing Well or Development Well may differ from these averages.
Chesapeake will retain 10% of the proceeds from the sale of oil, natural gas liquids and natural gas attributable to its net revenue interest in the Producing Wells,
and 50% of the proceeds from the sale of future production attributable to its net revenue interest in the Development Wells. Chesapeake initially will own 50% of the
trust units (without giving effect to the exercise of the underwriters’ option to purchase additional common units). By virtue of Chesapeake’s retained interest in the
Producing Wells and the Development Wells, as well as its ownership of 50% of the trust units, it would have an effective average net revenue interest of 29.0% in the
Producing Wells and 39.0% in the Development Wells, compared with an effective average net revenue interest for the holders of trust units other than Chesapeake of
23.8% in the Producing Wells and 13.0% in the Development Wells.
The trust will not be responsible for any costs related to the drilling of the Development Wells or any other operating and capital costs. The trust’s cash receipts
in respect of the trust properties will be determined after deducting post-production expenses and any applicable taxes associated with the PDP Royalty Interest and the
Development Royalty Interest. These post-production expenses will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate
and market the oil, natural gas liquids and natural gas produced. However, the trust will not be responsible for costs of marketing services provided by Chesapeake.
Cash distributions to unitholders will be increased or decreased by the effect of the trust’s hedging arrangements related to oil and natural gas liquids production and
reduced by trust expenses.
The trust will be a party to hedging arrangements covering a portion of its oil and natural gas liquids production through September 30, 2015. As a party to these
contracts, the trust will receive payments directly from its counterparties and be required to pay any amounts owed directly to its counterparties. The trust will hedge
approximately 50% of the expected oil and natural gas liquids production and 37% of the trust’s expected revenues (based on NYMEX strip oil prices as of October 14,
2011) upon which the target distributions from October 1, 2011 through September 30, 2015 are based. Following this offering, except in limited circumstances
involving the restructuring of an existing hedge, the trust will have no ability to terminate its hedging arrangements or enter into additional hedges. Except in connection
with the restructuring of an existing hedge, no production after September 30, 2015 will be hedged. The trust’s royalty interests in the Underlying Properties will be
pledged to the hedge counterparties to provide credit support for the hedge transactions, and the hedging counterparties may foreclose on such lien if, among other
things, the trust or Chesapeake is in material default of the drilling, payment or reporting obligations under the hedging arrangements, subject to applicable cure and
notice periods. Please see “The Trust—Hedging Arrangements” beginning on page 47 and “Target Distributions and Subordination and Incentive Thresholds”
beginning on page 50.
The trust will make quarterly cash distributions of substantially all of its cash receipts, after deducting the trust’s expenses, approximately 60 days following the
completion of each quarter through (and including) the quarter ending June 30, 2031. The first distribution, which will cover the third quarter of 2011 (consisting of
proceeds attributable to two months of production), is expected to be made on or about December 1, 2011 to record unitholders on or about November 21, 2011. The
Bank of New York Mellon Trust Company, N.A., as trustee, intends to withhold $1.0 million from the first distribution to establish an initial cash reserve available for
trust expenses.
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Index to Financial Statements
The PDP Royalty Interest and the Development Royalty Interest will each consist of two separate royalty interests conveyed by Chesapeake to the trust: (a) a
term royalty interest for a period of 20 years commencing on July 1, 2011 and ending on June 30, 2031 (such date is referred to as the “Termination Date” and such
interests are referred to as the “Term Royalties”) and (b) a perpetual royalty interest that does not terminate (together, the “Perpetual Royalties”). The trust will dissolve
and begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will revert
automatically to Chesapeake. Following the Termination Date, the Perpetual Royalties will be sold by the trust, and the net proceeds of the sale, as well as any
remaining trust cash reserves, will be distributed to the unitholders pro rata. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties from the
trust following the Termination Date.
Chesapeake currently operates 94% of the Producing Wells and expects to operate approximately 93% of the Development Wells until the completion of its
drilling obligation. Chesapeake will market, or cause to be marketed, the oil, natural gas liquids and natural gas produced from the Underlying Properties. The
conveyance instruments obligate Chesapeake to conduct operations and market production in good faith and in accordance with the Reasonably Prudent Operator
Standard described under “—The Development Wells” below.
Prior to fulfilling its drilling obligation to the trust, Chesapeake may cause the trust to exchange leased acreage in the AMI for other leased acreage in the
sections adjacent to the AMI (such adjacent sections are referred to as the “Development Area”). If additional acreage in the Development Area becomes subject to the
royalty interests, then the AMI will automatically expand to include such acreage. In addition, if Chesapeake acquires any additional leases or interests in the AMI,
Chesapeake may make such additional leases or interests subject to the royalty interests of the trust with respect to any Development Wells subsequently drilled on such
acreage. However, the aggregate acreage attributable to the exchanged leases or additional leases or acreage may not exceed five percent of the acreage initially subject
to the royalty interests and the reserve profile of the newly burdened acreage must be consistent with the reserve profile of the acreage released by the trust. See
“Description of the Royalty Interests—Additional Features of the Royalty Interests—Exchange and Addition of Acreage” on page 81.
Following the satisfaction of its drilling obligation to the trust, Chesapeake may, without the consent or approval of the trust unitholders, sell all or any part of its
retained interest in the Underlying Properties. In any such sale by Chesapeake, the Underlying Properties must be sold subject to and burdened by the trust’s royalty
interests, except that Chesapeake may require the trust to release the trust’s royalty interests on such Underlying Properties with an aggregate value of up to $5.0 million
during any 12-month period. In such event, the trust must receive an amount equal to the fair value to the trust of any royalty interests it sells. See “Description of the
Royalty Interests—Additional Features of the Royalty Interests—Sale and Release of Underlying Properties” on page 81.
The business and affairs of the trust will be managed by the trustee. The trustee will have no ability to manage or influence the operation of the Underlying
Properties. Chesapeake will have no ability to manage or influence the management of the trust except through its limited voting rights as a holder of trust units. Please
see “Description of the Trust Units—Voting Rights of Trust Unitholders” beginning on page 90.
The principal offices of the trust are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is (512) 236-6599.
The Development Wells
Pursuant to a development agreement with the trust, Chesapeake intends to drill, or cause to be drilled, 118 Development Wells in the AMI by June 30, 2015 and
is obligated to complete such drilling by June 30, 2016. Chesapeake will be credited for drilling one full Development Well if the perforated length of the well is equal
to or greater than 3,500 feet and Chesapeake’s net revenue interest in the well is equal to 52.0%. For wells with a perforated length that is less than 3,500 feet, and for
wells in which Chesapeake has a net revenue interest greater than or less than 52.0%, Chesapeake will receive proportionate credit. As a result, Chesapeake may be
required to
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drill more or less than 118 wells in order to fulfill its drilling obligation. See “The Trust—Development Agreement and Drilling Support Lien” beginning on page 45.
Since July 1, 2011, Chesapeake has drilled and completed six Development Wells and has drilled two additional wells in the AMI that are awaiting completion as of the
date of this prospectus. Assuming the successful completion of these two wells, such wells will count toward the satisfaction of Chesapeake’s drilling obligation.
Until Chesapeake has satisfied its drilling obligation, it will not be permitted to drill or complete any well on lease acreage included within the AMI for its own
account. For the life of the trust, Chesapeake will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated
interval of any Development Well or Producing Well.
In drilling the Development Wells, Chesapeake is required to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar
circumstances as if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such properties. We refer to
this standard as the “Reasonably Prudent Operator Standard.” Where Chesapeake does not operate the Underlying Properties, Chesapeake is required to use
commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying Properties to adhere to the Reasonably Prudent Operator
Standard. Chesapeake expects that the drilling and completion techniques used for the Development Wells will be generally consistent with those used for the
Producing Wells and other Colony Granite Wash producing wells outside of the AMI. The proved undeveloped reserves reflected in the reserve reports assume that
Chesapeake will drill and complete the 118 Development Wells with the same completion technique as the 69 Producing Wells.
Chesapeake will grant to the trust a lien on its interest in the AMI (except the Producing Wells and any other wells that are already producing and not subject to
the royalty interests) in order to secure the estimated amount of the drilling costs for the trust’s interests in the Development Wells (the “Drilling Support Lien”). The
amount obtained by the trust pursuant to the Drilling Support Lien initially may not exceed $262.7 million. As Chesapeake fulfills its drilling obligation over time,
Development Wells that are completed or that are perforated for completion and then plugged and abandoned will be released from the Drilling Support Lien and the
total dollar amount that may be recovered by the trust for Chesapeake’s failure to fulfill its drilling obligation will be proportionately reduced.
As of the date of this prospectus, Chesapeake’s drilling activity with respect to the Development Wells is consistent with the drilling schedule contemplated by
the development agreement. The drilling schedule provides that approximately 30 wells are expected to be drilled each year until the drilling obligation is fulfilled.
Underlying Properties
The Underlying Properties are located in the Colony Granite Wash play in Washita County in western Oklahoma. The Colony Granite Wash is a subset of the
greater Granite Wash plays of the Anadarko Basin. The Colony Granite Wash is situated at the eastern end of a series of Des Moines-age granite wash fields that extend
along the southern flank of the Anadarko basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water
turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately
11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of Colony Granite Wash ‘A’) and the top of the Prue formation (or
base of Colony Granite Wash ‘C’). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the
targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas
condensate reservoir based on reserve volumes. However, oil and natural gas liquids production generates more revenue than natural gas production in the Colony
Granite Wash due to prices that have historically been, and currently are, significantly higher for oil and natural gas liquids than for natural gas. Development costs for
horizontal wells drilled and completed in the AMI average
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approximately $8.31 per boe, which is comparable to the development costs in other large-scale resource developments in the Mid-Continent in which Chesapeake
operates.
Chesapeake began drilling horizontal wells in the Colony Granite Wash in 2007. Chesapeake is the largest leaseholder in the Colony Granite Wash, with
approximately 61,100 net acres (of which 28,700 net acres will be subject to the trust’s royalty interests), the most active driller in the play, based on rig count, and the
largest producer in the play. Since 2007, there have been 172 Des Moines horizontal wells drilled in the Colony Granite Wash. Of those 172 wells, Chesapeake has
drilled 132 wells and participated in another 35 wells. As of June 30, 2011, there were 15 rigs drilling horizontal wells in the formation, with nine of those rigs drilling
for Chesapeake. While horizontal wells are more expensive than vertical wells, a horizontal well increases the production of hydrocarbons and adds significant
recoverable reserves per well. In addition, an operator can achieve better returns on drilling investments with horizontal drilling because the production from one
horizontal well is equal to the production from several vertical wells. While Chesapeake is the most active company in this play, other operators in the Colony Granite
Wash include publicly-listed companies such as Penn Virginia Corporation, Apache Corporation, QEP Resources, Inc., SM Energy Company and Marathon Oil
Corporation, and privately-held companies such as Samson Oil & Gas Limited, Chaparral Energy, Inc. and Ward Petroleum Corporation.
Target Distributions and Subordination and Incentive Thresholds
Chesapeake has established quarterly target levels of cash distributions to unitholders for the life of the trust as set forth in Annex B to this prospectus. Actual
cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas liquids and natural gas produced from the Underlying
Properties, the prices received for such production, when Chesapeake receives payment for such production, payments under the hedge arrangements, the trust’s
expenses and other factors. As shown in Annex B, while target distributions initially increase as Chesapeake completes its drilling obligation and production increases,
over time target distributions decline as a result of the depletion of the reserves in the Underlying Properties. While these target distributions do not represent the actual
distributions you will receive with respect to your common units, they were used to calculate the subordination and incentive thresholds described in more detail below.
The target distributions were derived by assuming that oil, natural gas liquids and natural gas production from the trust properties will equal the volumes reflected in the
reserve reports included as Annex A to this prospectus and that prices received for such production will be consistent with settled NYMEX pricing for July through
October 2011, monthly NYMEX forward pricing as of October 14, 2011 for the remainder of the period ending June 30, 2014 and assumed price increases after June
30, 2014 of 2.5% annually, capped at $120.00 per bbl of oil and $7.00 per mmbtu of natural gas. Using these assumptions, the price of oil would reach the $120.00 per
bbl cap in 2026 and the price of natural gas would reach the $7.00 per mmbtu cap in 2028. The target distributions also give effect to estimated post-production
expenses, projected trust administrative expenses and actual production for July and August of 2011.
In order to provide support for cash distributions on the common units, Chesapeake has agreed to subordinate 11,437,500 of the trust units it will retain following
this offering, which will constitute 25% of the outstanding trust units. The subordinated units will be entitled to receive pro rata distributions from the trust each quarter
if and to the extent there is sufficient cash to pay a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is
not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated
for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all the common units, including the common units
held by Chesapeake. Each quarterly subordination threshold is 20% below the target distribution level for the corresponding quarter (each, a “subordination threshold”).
In exchange for agreeing to subordinate a portion of its trust units, and in order to provide additional financial incentive to Chesapeake to satisfy its drilling
obligation and perform operations on the Underlying
5
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Index to Financial Statements
Properties in an efficient and cost-effective manner, Chesapeake will be entitled to receive incentive distributions equal to 50% of the amount by which the cash
available for distribution on all of the trust units in any quarter is 20% greater than the target distribution for such quarter (each, an “incentive threshold”). The
remaining 50% of cash available for distribution in excess of the incentive thresholds will be paid to trust unitholders, including Chesapeake, on a pro rata basis.
By way of example, if the target distribution per unit for a particular quarterly period is $0.80, then the subordination threshold would be $0.64 and the incentive
threshold would be $0.96 for such quarter. This means that if the cash available for distribution to all holders for that quarter would result in a per unit distribution
below $0.64, the distribution to be made with respect to subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, up to the
amount of the subordination threshold, on the common units. If, on the other hand, the cash available for distribution to all holders would result in a per unit distribution
above $0.96, then Chesapeake would receive 50% of the amount by which the cash available for distribution on all the trust units exceeds $0.96, with all trust
unitholders (including Chesapeake on a pro rata basis) sharing in the other 50% of such excess amount. See “Target Distributions and Subordination and Incentive
Thresholds” beginning on page 50.
At the end of the fourth full calendar quarter following Chesapeake’s satisfaction of its drilling obligation with respect to the Development Wells, the
subordinated units will automatically convert into common units on a one-for-one basis and Chesapeake’s right to receive incentive distributions will terminate. After
such time, the common units will no longer have the protection of the subordination threshold, and all trust unitholders will share on a pro rata basis in the trust’s
distributions. Chesapeake currently intends to complete its drilling obligation on or before June 30, 2015 and accordingly, Chesapeake expects the subordinated units
will convert into common units on or before June 30, 2016. Chesapeake is obligated to complete its drilling obligation by June 30, 2016, in which event the
subordinated units would convert into common units on or before June 30, 2017. The period during which the subordinated units are outstanding is referred to as the
“subordination period.”
Chesapeake’s management has prepared the prospective financial information set forth below to present the target cash distributions to the holders of
the trust units based on the estimates and assumptions described under “Target Distributions and Subordination and Incentive Thresholds” beginning on
page 50. The accompanying prospective financial information was not prepared with a view toward complying with the regulations of the U.S. Securities and
Exchange Commission (the “SEC”) or the guidelines established by the American Institute of Certified Public Accountants with respect to preparation and
presentation of prospective financial information. More specifically, such information omits items that are not relevant to the trust. Chesapeake’s
management believes the prospective financial information was prepared on a reasonable basis, reflects the best currently available estimates and judgments,
and presents, to the best of management’s knowledge and belief, the expected course of action and the expected future financial performance of the royalty
interests. However, this information is based on estimates and judgments, and readers of this prospectus are cautioned not to place undue reliance on the
prospective production or financial information.
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, Chesapeake’s management.
PricewaterhouseCoopers LLP, the trust’s and Chesapeake’s independent registered public accountant, has neither examined, compiled nor performed any
procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion
or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included or incorporated by reference in this prospectus
relate to the Statement of Assets and Trust Corpus of the trust, the historical Statements of Revenues and Direct Operating Expenses of the Underlying
Properties and the historical financial statements of Chesapeake. The reports do not extend to the prospective financial information and should not be read to
do so.
6
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Index to Financial Statements
The following table sets forth the target distributions and subordination and incentive thresholds for each calendar quarter through the second quarter of 2017
(the last quarter for which subordinated units would be outstanding if Chesapeake does not complete its drilling obligation on or before June 30, 2016). The effective
date of the conveyance of the royalty interests is July 1, 2011, which means that the trust will be credited with the proceeds of production attributable to the royalty
interests from that date even though the trust properties will not be conveyed to the trust until the closing of this offering. Please see “—Calculation of Target
Distributions” below. The first distribution, which will cover the third quarter of 2011, is expected to be made on or about December 1, 2011 to record unitholders on or
about November 21, 2011. Due to the timing of the payment of production proceeds to the trust, the trust expects that the first distribution will include royalties
attributable to sales of oil, natural gas liquids and natural gas for two months (July and August 2011). Thereafter, quarterly distributions will generally include royalties
attributable to sales of oil, natural gas liquids and natural gas for three months, including the first two months of the quarter just ended and the last month of the quarter
prior to that one. The trustee intends to withhold $1.0 million from the first distribution to establish an initial cash reserve available for trust expenses.
Period
Subordination
Threshold (1)
Target
Distribution
(per unit)
2011:
Third Quarter(2)
Fourth Quarter
$
$
0.37
0.56
0.46
0.70
Incentive
Threshold (1)
$
0.55
0.85
2012:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.59
0.61
0.63
0.68
0.74
0.76
0.79
0.85
0.89
0.91
0.95
1.02
2013:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.70
0.70
0.72
0.70
0.87
0.87
0.90
0.88
1.05
1.05
1.08
1.05
2014:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.70
0.69
0.70
0.67
0.88
0.86
0.87
0.84
1.06
1.04
1.05
1.00
2015:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.67
0.69
0.65
0.56
0.84
0.86
0.81
0.70
1.00
1.03
0.97
0.84
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.51
0.47
0.44
0.42
0.64
0.59
0.55
0.52
0.77
0.71
0.66
0.62
2017
First Quarter
Second Quarter
0.39
0.38
0.49
0.47
0.59
0.56
7
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Index to Financial Statements
(1)
The subordination and incentive thresholds terminate after the fourth full calendar quarter following Chesapeake’s completion of its drilling obligation.
(2)
Includes proceeds attributable to two months of actual production from July 1, 2011 to August 31, 2011, and gives effect to the establishment of $1.0 million of reserves for
expenses withheld by the trustee.
For additional information with respect to the subordination and incentive thresholds, please see “Target Distributions and Subordination and Incentive
Thresholds” beginning on page 50.
8
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Index to Financial Statements
Calculation of Target Distributions
The following table presents the calculation of the target distributions for each quarter through and including the quarter ending June 30, 2012. The target
distributions were prepared by Chesapeake based on assumptions of production volumes, pricing and other factors. The production forecasts used to calculate target
distributions are based on estimates by Ryder Scott contained in the reserve reports. Payments to unitholders will be made approximately 60 days following the end of
each calendar quarter. Please read “Target Distributions and Subordination and Incentive Thresholds—Significant Assumptions Used to Calculate the Target
Distributions” beginning on page 56.
Three Months Ending
September 30,
2011 (1)
Period
Estimated production from trust properties
Oil sales volumes (mbbls)
Natural gas liquids sales volumes (mbbls)
Natural gas sales volumes (mmcf)
Total sales volumes (mboe)
% PDP sales volumes
% PUD sales volumes
% Oil volumes
% Natural gas liquids volumes
% Natural gas volumes
Commodity price and derivative contract positions
NYMEX futures price(2)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Natural gas ($/mmbtu)
Assumed realized weighted unhedged price(3)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Natural gas ($/mcf)
Assumed realized weighted hedged price(4)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Percent of oil volumes hedged
Oil hedged price ($/bbl)
Percent of natural gas liquids volumes hedged
Natural gas liquids hedged price ($/bbl)
Estimated cash available for distribution
Oil sales revenues
Natural gas liquids sales revenues
Natural gas sales revenues
Realized gains (losses) from derivative contracts
December 31
,
March 31,
2011 (1)
2012 (1)
(In thousands, except volumetric and per unit data)
June 30,
2012 (1)
103
179
1,720
178
299
2,876
181
302
2,909
181
304
2,923
569
956
967
972
100%
—
84%
16%
69%
31%
61%
39%
18%
32%
50%
19%
31%
50%
19%
31%
50%
19%
31%
50%
$
$
$
95.93
47.15
4.36
$
$
$
86.03
42.31
3.78
$
$
$
87.10
42.85
4.06
$
$
$
87.35
42.97
4.07
$
$
$
92.35
44.76
3.12
$
$
$
82.45
40.01
2.48
$
$
$
83.52
40.46
2.81
$
$
$
83.77
40.45
2.98
$
$
92.35
44.76
—
—
—
—
$
$
81.56
39.57
33.1%
84.18
33.6%
41.41
$
$
82.34
39.88
49.9%
84.74
50.0%
41.68
$
$
82.83
39.99
50.0%
85.48
50.0%
42.05
9,554
8,030
5,358
—
$
$
Operating revenues and realized gains (losses) from
derivative contracts
Production taxes
Trust administrative expenses(5)
Total trust expenses
$
$
14,648
11,953
7,120
(289)
$
$
$
$
$
15,083
12,220
8,172
(389)
$ 15,175
12,278
8,707
(309)
22,942
(726)
(1,327)
33,432
(935)
(250)
35,085
(938)
(250)
35,851
(930)
(250)
(2,053)
(1,185)
(1,188)
(1,180)
Cash available for distribution
$
20,890
$
32,247
$
33,896
$ 34,670
Trust units outstanding
Target distribution per trust unit
$
45,750
0.46
$
45,750
0.70
$
45,750
0.74
$
45,750
0.76
Subordination threshold per trust unit
$
0.37
$
0.56
$
0.59
$
0.61
Incentive threshold per trust unit
$
0.55
$
0.85
$
0.89
$
0.91
9
Table of Contents
Index to Financial Statements
(1)
The three months ending September 30, 2011 include proceeds attributable to two months of production from July 1, 2011 to August 31, 2011. Thereafter, quarterly
distributions will generally include royalties attributable to sales of oil, natural gas liquids and natural gas for three months, including the first two months of the quarter just
ended as well as the last month of the quarter prior to that one.
(2)
Average NYMEX settled and futures prices, as reported October 14, 2011. For a description of the effect of lower NYMEX prices on target cash distributions, please read
“Target Distributions and Subordination and Incentive Thresholds—Sensitivity of Target Distributions to Changes in Oil, Natural Gas Liquids and Natural Gas Prices and
Volumes” beginning on page 61.
(3)
Sales price net of forecasted gravity quality, btu content, transportation costs, and marketing costs. For information about the estimates and assumptions made in preparing
the table above, see “Target Distributions and Subordination and Incentive Thresholds—Significant Assumptions Used to Calculate the Target Distributions” beginning on
page 56.
(4)
No hedging arrangements will cover natural gas.
Includes the establishment of an initial cash reserve of $1.0 million for trust expenses in period ending September 30, 2011.
(5)
Chesapeake Energy Corporation
Chesapeake is the second-largest producer of natural gas, is among the top 15 producers of oil and natural gas liquids and is the most active driller, based on rig
count, of new oil and natural gas wells in the U.S. Chesapeake’s operations are focused on discovering and developing unconventional natural gas and oil fields onshore
in the U.S. Chesapeake owns leading positions in the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and in the Granite Wash, Cleveland,
Tonkawa, Mississippian, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Frontier, Codell, Bakken/Three Forks and Utica unconventional liquids
plays. It has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. As of June 30, 2011, Chesapeake
had total assets of approximately $36.7 billion and total estimated net proved reserves of 16.5 tcfe. Chesapeake has approximately 61,100 net acres leased in the Colony
Granite Wash and as of June 30, 2011, Chesapeake was operating nine rigs in the Colony Granite Wash.
Chesapeake’s principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and its telephone number is
(405) 848-8000. Chesapeake’s website is www.chk.com ; however, the information contained on Chesapeake’s website is not incorporated by reference into this
prospectus.
The trust units do not represent interests in or obligations of Chesapeake.
Key Investment Considerations
The following are some key investment considerations related to the Underlying Properties, the royalty interests and the common units:
•
The royalty interests being contributed to the trust are from the highly-productive Colony Granite Wash Play. The existing Producing Wells
and the Development Wells to be drilled target the Colony Granite Wash play within the broader Granite Wash formation of the Anadarko
Basin, which is the largest non-shale resource play in the Mid-Continent. This highly-productive play has been a focus area for recent
development, with 172 horizontal wells targeting the Des Moines formation drilled in the Colony Granite Wash since 2007. Of those 172 wells,
Chesapeake has drilled 132 wells and participated in another 35 wells. As of June 30, 2011, there were 15 active rigs drilling horizontal wells
in the play, with nine of those rigs drilling for Chesapeake.
•
Liquids-weighted revenue and production profiles provide long-term exposure to oil prices. Over the 20-year producing life of the trust, 72%
of net revenues (based on October 14, 2011 strip prices) and 48% of production are projected to be derived from oil and natural gas liquids.
Although natural gas liquids typically sell for less than oil on a volume equivalency basis, natural gas liquids prices have historically been
highly correlated with oil prices. As a result, the unhedged portion of liquids revenues
10
Table of Contents
Index to Financial Statements
during the hedge period and all liquids revenues beyond the hedge period are directly exposed to oil prices, and the amount of trust distributions
and consequently trust performance is expected to be highly correlated to fluctuations in the price of oil.
•
Royalty interests not burdened by operating or capital costs. The trust will not be responsible for any operating or capital costs associated with
the Underlying Properties, including the costs to drill and complete the Development Wells. The trust will bear its proportionate share of
post-production expenses, any applicable taxes and trust expenses.
•
Exposure to oil and natural gas liquids price volatility mitigated through September 30, 2015. The trust will be a party to hedging
arrangements covering a portion of the trust’s expected oil and natural gas liquids production through September 30, 2015. The trust will hedge
approximately 50% of the expected oil and natural gas liquids production and approximately 37% of the trust’s expected revenues (based on
NYMEX strip oil prices as of October 14, 2011) upon which the target distributions from October 1, 2011 through September 30, 2015 are
based. These hedging arrangements are expected to reduce the trust’s exposure to fluctuations in the prices of oil through the third quarter of
2015.
•
Alignment of interests between Chesapeake and the trust unitholders. Chesapeake has significant incentives to complete its drilling obligation
and increase production from the Underlying Properties as a result of the following factors:
•
Chesapeake will initially have a significant economic interest in the Underlying Properties through its 50% retained interest in the
Development Wells, 10% retained interest in the Producing Wells and its ownership of approximately 50% of the trust units.
•
A portion of the trust units that Chesapeake will own, constituting 25% of the total outstanding trust units, will be subordinated units
that will not be entitled to receive distributions unless there is sufficient cash to pay the subordination threshold amount to the common
units. In addition, these subordinated units will only convert into common units at the end of the fourth full calendar quarter following
Chesapeake’s satisfaction of its drilling obligation to the trust.
•
To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period,
Chesapeake will be entitled to receive 50% of such cash as incentive distributions, plus its pro rata share of the remaining 50% of such
cash by virtue of its ownership of 22,875,000 total units.
•
Chesapeake will not be permitted to drill or complete any wells for its own account within the AMI or sell the Underlying Properties
until it has satisfied its drilling obligation.
•
If Chesapeake does not fulfill its drilling obligation by June 30, 2016, the trust may foreclose on the Drilling Support Lien on the
Underlying Properties. See “The Trust—Development Agreement and Drilling Support Lien” beginning on page 45.
•
The Colony Granite Wash represents a core asset for Chesapeake. The approximately 61,100 net acres held by Chesapeake in the Colony
Granite Wash represent one of its core assets. Chesapeake has grown its position in the Colony Granite Wash since it began drilling horizontal
wells there in 2007 based on its belief that the formation can provide attractive returns on invested capital and its belief that the play will
further Chesapeake’s goal of increasing the proportion of its liquids production. As of June 30, 2011, Chesapeake had nine rigs drilling
horizontal wells in the Colony Granite Wash.
•
Chesapeake is an experienced operator in the Colony Granite Wash. Since 2007, Chesapeake has drilled, as operator, 132 of the 172 horizontal
wells drilled by the industry in the Colony Granite Wash to date, 129 of which are completed and the remaining three of which are awaiting
completion and expected to be productive. Of the 132 horizontal wells drilled by Chesapeake in the Colony Granite Wash, 124 are located in
Washita County, in which the Underlying Properties are located. Chesapeake expects to operate
11
Table of Contents
Index to Financial Statements
approximately 93% of the Development Wells until the completion of its drilling obligation, allowing Chesapeake to control the timing and
amount of discretionary expenditures for operational and development activities with respect to the majority of the Development Wells.
•
The Colony Granite Wash is serviced by well-developed gathering systems and transportation pipelines. Chesapeake’s affiliate, Chesapeake
Midstream Partners, L.P. (“Chesapeake Midstream Partners”), provides Chesapeake with gathering, treating and compression services for
natural gas produced in the Colony Granite Wash and is expected to continue to provide these services with respect to substantially all of the
natural gas and natural gas liquids produced by the Underlying Properties. The natural gas gathering systems are connected to an extensive
intrastate natural gas transportation pipeline system owned by Enogex LLC (“Enogex”), a subsidiary of publicly-held OGE Energy Corp.
Chesapeake’s wholly owned subsidiary, Chesapeake Midstream Development, L.P. (“Chesapeake Midstream Development”), gathers oil
production from the Colony Granite Wash through its gathering systems and third parties gather other oil by truck. The oil is further
transported to Plains All American Pipeline, L.P. (“Plains”), a publicly-held master limited partnership, through its pipeline and by truck. The
well-developed gathering systems in the Colony Granite Wash and Chesapeake’s affiliation with the primary service providers allow close
coordination regarding the availability of midstream services and reduce the risk that such services would not be available as Development
Wells are drilled.
•
Rigs and services readily available to allow timely drilling and completion of wells. Chesapeake’s substantial oilfield service operations,
including drilling rigs, pressure pumping equipment, trucking, oilfield tools, location and road construction and roustabout services, support its
drilling activities and will allow Chesapeake to manage the development of the trust’s leasehold efficiently and strategically. As of June 30,
2011, Chesapeake had nine drilling rigs operating in the Colony Granite Wash and owned or leased a total of 133 drilling rigs, which it uses to
drill wells for its own account. Chesapeake estimates that only four to five rigs will be required to complete its drilling obligation within its
contractual commitment to the trust. Chesapeake may use a combination of its own rigs and oilfield service businesses and third party rigs and
services to drill and complete the Development Wells. Chesapeake’s direct access to drilling rigs and related oilfield services should
substantially mitigate any potential shortage of drilling and completion equipment and enable Chesapeake to achieve its projected drilling
schedule.
•
Potential for initial depletion to be offset by results of development drilling. Chesapeake intends to drill, or cause to be drilled, all of the
Development Wells on PUD drilling locations in the AMI by June 30, 2015 and is obligated to complete such drilling by June 30, 2016.
Furthermore, Chesapeake is incentivized to increase production in the near term due to its substantial ownership of trust units, the
subordination and incentive distribution provisions of those units and its retained interest in the Underlying Properties. While production from
the trust properties will decline over the long term, the anticipated production from the Development Wells is expected to more than offset
depletion of the Producing Wells during the drilling period.
•
Recognized sponsor with a successful track record and active drilling program. Chesapeake maintains the industry’s most active drilling
program, based on rig count. In 2010, Chesapeake drilled 1,445 gross (938 net) operated wells and participated in another 1,586 gross (211 net)
wells operated by other companies. Chesapeake’s drilling success rate in 2010 was 98% for both company-operated and non-operated wells.
Daily production for 2010 averaged 2.836 bcfe, an increase of 355 mmcfe, or 14%, over the 2.481 bcfe of daily production for 2009, and
consisted of 2.534 bcf of natural gas (89% on a natural gas equivalent basis) and 50,397 bbls of oil and natural gas liquids (11% on a natural
gas equivalent basis). 2010 was Chesapeake’s 21st consecutive year of production growth.
12
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Index to Financial Statements
Proved Reserves
Proved Reserves of Underlying Properties and Royalty Interests. The following table sets forth certain estimated proved reserves and the PV-10 value as of June
30, 2011 attributable to the Underlying Properties, the PDP Royalty Interest and the Development Royalty Interest, in each case derived from the reserve reports. The
reserve reports were prepared by Ryder Scott in accordance with criteria established by the SEC.
Proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property attributable to Chesapeake’s
interest by the royalty interest assigned to the trust in each property. The reserves related to the Underlying Properties include all proved reserves expected to be
economically produced during the life of the properties. The reserves attributable to the trust’s interests include only the reserves attributable to the Underlying
Properties that are expected to be produced within the 20-year period prior to the Termination Date as well as the residual 50% interest in the royalty interests that the
trust will own on the Termination Date and subsequently sell. A summary of the reserve reports is included as Annex A to this prospectus.
Proved Reserves(1)
Oil
(mbbl)
Underlying Properties:
Developed
Undeveloped
Total
Royalty Interests:
Developed (90%)
Undeveloped (50%)
Total
(1)
Natural Gas
Liquids (mbbl)
Total
(mboe)
PV-10 Value(2)
(In thousands)
2,648
8,290
7,791
18,640
75,689
179,931
23,054
56,919
343,504
510,087
10,938
26,431
255,620
79,973
853,591
2,233
4,002
6,235
8,319
60,536
80,325
18,557
25,709
325,434
485,706
6,235
14,554
140,861
44,266
811,140
The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas liquids and natural gas for the
period from July 1, 2010 through June 1, 2011, without giving effect to derivative transactions, and were held constant for the life of the properties. The prices used in the
reserve reports, as well as Chesapeake’s internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and
adjusted for transportation and regional price differentials and, for the royalty interests, costs of marketing services provided by Chesapeake affiliates, which will not be
charged to the trust. The reference prices and the equivalent weighted average wellhead prices as of June 30, 2011 are presented in the table below.
Oil
(per bbl)
$
89.86
$
86.08
$
86.09
Trailing 12-month average pricing
Weighted average wellhead prices (Underlying Properties)
Weighted average wellhead prices (royalty interests)
(2)
Natural Gas
(mmcf)
Natural gas
liquids
(per bbl)
$
89.86
$
39.83
$
39.80
Natural gas
(per mcf)
$
4.21
$
2.93
$
2.86
PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10% (as
required by the SEC), calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from standardized measure of
discounted net cash flows, or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future
net revenues. Because the historical financial information related to the Underlying Properties consists solely of revenues and direct operating expenses and does not include
the effect of income taxes, we expect the PV-10 and Standardized Measure attributable to the Underlying Properties for each period to be the same. Because the trust will not
bear federal income tax expense, we also expect the PV-10 and Standardized Measure attributable to the royalty interests for each period to be the same. Neither PV-10 nor
Standardized Measure represents an estimate of the fair market value of the Underlying Properties or the royalty interests. We and others in our industry use PV-10 as a
measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. PV-10 for the royalty
interests has been calculated without deduction for production and development costs, as the trust will not bear those costs.
13
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Index to Financial Statements
At the Termination Date, the estimated reserves attributable to the residual 50% interest in the royalty interests that the trust will own on the Termination Date
and subsequently sell are 5.0 mmboe. The PV-10 value of such reserves calculated using 12-month trailing SEC pricing as of June 30, 2011 is $9.2 million.
Underlying Production Attributable to Target Distributions. The following production bar graph summarizes estimated production underlying trust revenues
used to determine Target Distributions.
(1)
(2)
Due to the July 1, 2011 effective date of the royalty interests and the timing of payments received by the trust for production in determining Target Distributions, the 2011
production forecast includes production from July 1, 2011 through November 30, 2011.
Due to the June 30, 2031 termination date of the trust and the timing of payments received by the trust for production in determining Target Distributions, the 2031
production forecast includes production from December 1, 2030 to June 30, 2031.
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Key Risk Factors
Below is a summary of certain key risk factors related to the Underlying Properties, the royalty interests and the common units. This list is not exhaustive. Please
also read carefully the full discussion of these risks and other risks described under “Risk Factors” beginning on page 20.
•
Drilling for and producing oil, natural gas liquids and natural gas on the Underlying Properties are high risk activities with many uncertainties
that could delay the anticipated drilling schedule for the Development Wells and adversely affect future production from the Underlying
Properties. Any such delays or reductions in production could decrease cash available for distributions to unitholders.
•
Prices of oil, natural gas liquids and natural gas fluctuate due to a number of factors that are beyond the control of the trust and Chesapeake,
and lower prices could reduce proceeds to the trust, Chesapeake’s economic incentive to drill and cash distributions to unitholders.
•
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the
trust units.
•
Estimates of target distributions to unitholders, subordination thresholds and incentive thresholds are based on assumptions that are inherently
subjective and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause
actual cash distributions to differ materially from those estimated.
•
Chesapeake may not serve as the operator of as many of the Developmental Wells as it expects and Chesapeake will rely upon unaffiliated
third parties, who may be less qualified, to drill Development Wells where Chesapeake is not the operator.
•
The oil, natural gas liquids and natural gas reserves estimated to be attributable to the Underlying Properties are depleting assets and production
from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and gas properties or royalty interests
to replace the depleting assets and production.
•
The hedging arrangements for the trust will cover only a portion of the production attributable to the trust, such arrangements will limit the
trust’s ability to benefit from commodity price increases for hedged volumes, and such arrangements will be secured by the trust’s royalty
interests in the Underlying Properties and may require the trust to make cash payments in excess of its receipts. Following this offering, except
in limited circumstances involving the restructuring of an existing hedge, the trust will have no ability to terminate its hedging arrangements or
enter into additional hedges. The hedging counterparties may foreclose on their lien on the trust’s royalty interests in certain circumstances.
•
Conflicts of interest could arise between Chesapeake and the trust.
•
Potential legislative and regulatory actions could increase Chesapeake’s costs, reduce its revenue and cash flow from the sale of oil, natural gas
liquids and natural gas, reduce its liquidity or otherwise alter the way it conducts business.
•
The trust’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the U.S. Internal Revenue Service
(“IRS”) were to treat the trust as a corporation for U.S. federal income tax purposes or the trust were subjected to state or local entity level tax,
then its cash available for distribution to unitholders would be substantially reduced.
•
The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
•
The trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the tax positions the
trust takes, the value of the trust units may be adversely affected, the cost of any IRS contest will reduce the trust’s cash available for
distribution and income, gain, loss and deduction may be reallocated among trust unitholders.
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Structure of the Trust
The following chart shows the relationship of Chesapeake, the trust and the public unitholders immediately following this offering (without giving effect to the
exercise of the underwriters’ option to purchase additional common units).
*
Chesapeake is expected to have an effective average net revenue interest of 29.0% in the Producing Wells and 39.0% in the Development Wells. Public unitholders (that is, holders of trust
units other than Chesapeake) are expected to have an effective average net revenue interest of 23.8% in the Producing Wells and 13.0% in the Development Wells.
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Index to Financial Statements
The Offering
Common units offered to public
22,875,000 common units (26,306,250 common units, if the underwriters exercise their option to
purchase additional common units in full)
Trust units owned by Chesapeake after the offering
11,437,500 common units and 11,437,500 subordinated units (8,006,250 common units and
11,437,500 subordinated units, if the underwriters exercise their option to purchase additional
common units in full)
Total units outstanding after the offering
34,312,500 common units and 11,437,500 subordinated units
Option to purchase additional common units
3,431,250 common units will be issued and retained by the trust at the initial closing, to be used to
satisfy (if necessary) the 30-day option to purchase additional units granted to the underwriters. If
the underwriters exercise their option to purchase additional common units, the trust will sell to
the underwriters such number of the retained units as is necessary to satisfy the option to purchase
additional common units, and will then deliver the net proceeds of such sale, together with any
remaining unsold units, to one or more subsidiaries of Chesapeake as partial consideration for the
conveyance of the Perpetual Royalties. If the underwriters do not exercise their option to purchase
additional common units, the retained units will be delivered to one or more subsidiaries of
Chesapeake as partial consideration for the conveyance of the Perpetual Royalties, promptly
following the 30th day after the date of this prospectus. See “The Trust—Formation Transactions”
beginning on page 44.
Use of proceeds
The trust is offering the common units to be sold in this offering. Assuming no exercise of the
underwriters’ option to purchase additional common units and an initial public offering price of
$20.00 per common unit (the midpoint of the price range set forth on the cover page of this
prospectus), the estimated net proceeds of this offering will be approximately $426.3 million, after
deducting underwriting discounts and commissions, the structuring fee and estimated offering
expenses. The trust will deliver the net proceeds to a wholly owned subsidiary of Chesapeake, as
consideration for the conveyance of the Term Royalties and as partial consideration for the
conveyance of the Perpetual Royalties. See “The Trust—Formation Transactions” beginning on
page 44.
Chesapeake intends to use any proceeds it receives from the sale of the royalty interests to the trust
to repay borrowings under its credit facility. Chesapeake may re-borrow amounts under its credit
facility from time to time and does so for general corporate purposes, including capital
expenditures for land, drilling and other costs. See
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“Use of Proceeds” on page 42. Affiliates of certain of the underwriters are lenders under
Chesapeake’s credit facility and, in that respect, will receive a substantial portion of the proceeds
from this offering through the repayment of borrowings outstanding under the facility. See
“Underwriting” beginning on page 113.
NYSE symbol
“CHKR”
Trustee
The Bank of New York Mellon Trust Company, N.A.
Quarterly cash distributions
Quarterly cash distributions during the term of the trust will be made by the trustee approximately
60 days following the end of each calendar quarter to unitholders of record approximately 50 days
following the end of each calendar quarter. The first distribution, which will cover the third
quarter of 2011 (consisting of proceeds attributable to two months of production), is expected to
be made on or about December 1, 2011 to record unitholders on or about November 21, 2011. The
trustee intends to withhold $1.0 million from the first distribution to establish an initial cash
reserve available for trust expenses. Thereafter, quarterly distributions will generally include
royalties attributable to sales of oil, natural gas liquids and natural gas for three months, including
the first two months of the quarter just ended and the last month of the quarter prior to that one.
Actual cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of
oil, natural gas liquids and natural gas produced from the Underlying Properties, the prices
received for such production, when Chesapeake receives payment for such production, payments
under the hedge arrangements, the trust’s administrative expenses and other factors. Because
payments to the trust will be generated by depleting assets and production from the Underlying
Properties will diminish over time, a portion of each distribution will represent a return of your
original investment. Given that the production from the Underlying Properties is expected to
initially increase and then subsequently decline over time, the target distributions are also expected
to initially increase before declining over time.
Voting rights in the trust
Matters voted on by trust unitholders will generally be subject to approval by a majority of the
common units (excluding common units owned by Chesapeake and its affiliates) and a majority of
the trust units, in each case voting in person or by proxy at a meeting of such holders at which a
quorum is present. Chesapeake and its affiliates will not be entitled to vote on the removal of the
trustee or appointment of a successor trustee. However, if at any time Chesapeake and its affiliates
own less than 10% of the outstanding trust units, matters voted on by trust unitholders will be
subject to approval by a majority of the trust units, including units owned by Chesapeake, voting
in person or by proxy at a meeting of such holders at which a quorum is present. The trust does not
intend to hold annual meetings of the trust unitholders.
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Termination of the trust
U.S. federal income tax considerations
The trust will dissolve and begin to liquidate on the Termination Date, which is June 30, 2031, and
will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties
will revert automatically to Chesapeake. The Perpetual Royalties will be retained by the trust at
the Termination Date and thereafter sold, and the net proceeds of the sale, as well as any
remaining trust cash reserves, will be distributed to the unitholders pro rata. Chesapeake will have
a right of first refusal to purchase the royalty interests retained by the trust at the Termination
Date.
The trust will be treated as a partnership for U.S. federal income tax purposes. Consequently, the
trust will not incur any U.S. federal income tax liability. Instead, trust unitholders will be allocated
an amount of the trust’s income, gain, loss or deductions corresponding to their interest in the
trust, which amounts may differ in timing or amount from actual cash distributions.
The Term Royalty for the Producing Wells will and the Term Royalty for the Development Wells
should be treated as debt instruments for U.S. federal income tax purposes. The trust will be
required to treat a portion of each payment it receives with respect to each such royalty interest as
interest income in accordance with the “noncontingent bond method” under the original issue
discount rules contained in the Internal Revenue Code of 1986, as amended, and the corresponding
IRS regulations.
The Perpetual Royalty for the Producing Wells will and the Perpetual Royalty for the Development
Wells should be treated as mineral royalty interests for U.S. federal income tax purposes,
generating ordinary income subject to depletion.
Please read “U.S. Federal Income Tax Considerations” beginning on page 95 for more information.
Estimated ratio of taxable income to distributions
The trust estimates that if you own the units you purchase in this offering through the record date
for distributions for the period ending December 31, 2014, you will be allocated, on a cumulative
basis, an amount of federal taxable income for that period that will be approximately 55% of the
cash distributed to you with respect to that period. For example, if you receive an annual
distribution of $1.00 per unit, the trust estimates that your average allocable federal taxable
income per year will be approximately $0.55 per unit.
Please read “U.S. Federal Income Tax Considerations” beginning on page 95 for more information.
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Index to Financial Statements
RISK FACTORS
Before making an investment decision, you should carefully consider the risks described below and the risks described in Chesapeake’s Annual Report on Form
10-K for the year ended December 31, 2010, which is incorporated herein by reference. The trust’s cash available for distribution could be materially adversely
affected by any of these risks. The trading price of the common units could decline due to any of these risks, and you may lose all or part of your investment.
Risks Related to the Units
Drilling for and producing oil, natural gas liquids and natural gas on the Underlying Properties are high risk activities with many uncertainties that could delay the
anticipated drilling schedule for the Development Wells and adversely affect future production from the Underlying Properties. Any such delays or reductions in
production could decrease cash available for distribution to unitholders.
The drilling and completion of the Development Wells are subject to numerous risks beyond Chesapeake’s and the trust’s control, including risks that could
delay or change the current drilling schedule for the Development Wells and the risk that drilling will not result in commercially viable oil, natural gas liquids and
natural gas production. Drilling for oil, natural gas liquids and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient
revenues to return a profit. Chesapeake’s and third-party operators’ decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the
evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject
to varying interpretations. The costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures could
cause Chesapeake to re-direct its drilling capital to other plays and delay the drilling of the Development Wells beyond what was assumed in establishing target levels
of cash distributions to unitholders. Drilling and production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors,
including the following:
•
delays imposed by or resulting from compliance with regulatory requirements, including permitting;
•
unusual or unexpected geological formations and miscalculations or irregularities in formations;
•
shortages of or delays in obtaining equipment and qualified personnel;
•
equipment malfunctions, failures or accidents;
•
lack of available gathering facilities or delays in construction of gathering facilities;
•
lack of available capacity on interconnecting transmission pipelines;
•
unexpected operational events and drilling conditions;
•
pipe or cement failures and casing collapses;
•
pressures, fires, blowouts and explosions;
•
lost or damaged drilling and service tools;
•
loss of drilling fluid circulation;
•
lack of sufficient water or water disposal facilities in connection with hydraulic fracturing;
•
uncontrollable flows of oil, natural gas liquids and natural gas water or drilling fluids;
•
natural disasters;
•
environmental hazards, such as oil, natural gas liquids or natural gas leaks, pipeline ruptures and discharges of toxic gases or fluids;
•
adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes;
20
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Index to Financial Statements
•
reductions in oil, natural gas liquids and natural gas prices or, for hedged production, increases in pricing differentials; and
•
title problems affecting the Underlying Properties.
If drilling of Development Wells is delayed or the Producing Wells or Development Wells have lower than anticipated production due to one of the factors
above or for any other reason, cash distributions to unitholders may be reduced.
In addition, Development Wells may not be successful and Chesapeake is not obligated to drill replacement wells if this occurs. Under the Development
Agreement, Chesapeake will receive credit for drilling a Development Well if the well is drilled in the AMI and perforated horizontally for completion in the Colony
Granite Wash, even if such well does not successfully produce hydrocarbons. Additionally, once Chesapeake plugs and abandons an unsuccessful Development Well,
that well will be released from the Drilling Support Lien.
Prices of oil, natural gas liquids and natural gas fluctuate due to a number of factors that are beyond the control of the trust and Chesapeake, and lower prices
could reduce proceeds to the trust, Chesapeake’s economic incentive to drill and cash distributions to unitholders.
The trust’s reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of oil, natural gas liquids and natural gas. The
markets for these commodities are very volatile. Oil, natural gas liquids and natural gas prices can fluctuate widely in response to a variety of factors that are beyond the
control of the trust and Chesapeake. These factors include, among others:
•
regional, domestic and foreign supply, and perceptions of supply, of oil, natural gas liquids and natural gas;
•
the price and level of foreign imports of oil, natural gas liquids and natural gas, including political instability or armed conflict in producing regions;
•
U.S. and worldwide political and economic conditions;
•
the level of demand, and perceptions of demand, for oil, natural gas liquids and natural gas;
•
weather conditions and seasonal trends;
•
anticipated future prices of oil, natural gas liquids, natural gas, alternative fuels and other commodities;
•
technological advances affecting energy consumption and energy supply;
•
the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
•
natural disasters;
•
the nature and extent of domestic and foreign governmental regulations and taxation;
•
energy conservation and environmental measures;
•
the price and availability of alternative fuels and energy sources;
•
the level and effect of trading in commodity futures markets, including by commodity price speculators and others; and
•
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls.
For oil, from 2007 through September 30, 2011, the highest monthly NYMEX settled price was $134.62 per bbl and the lowest was $33.87 per bbl. For natural
gas, from 2007 through September 30, 2011, the highest monthly NYMEX settled price was $13.11 per mmbtu and the lowest was $2.84 per mmbtu. In addition, the
market price of oil, natural gas liquids and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil,
natural gas liquids and natural gas for heating purposes during the winter season.
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Index to Financial Statements
Lower oil, natural gas liquids and natural gas prices will reduce proceeds to which the trust is entitled and may ultimately reduce the amount of oil, natural gas
liquids and natural gas that is economic to produce from the Underlying Properties. As a result, Chesapeake or any third-party operator of any of the Underlying
Properties could determine during periods of low oil, natural gas liquids and natural gas prices to shut in or curtail production from wells on the Underlying Properties.
In addition, the operator of the Underlying Properties could determine during periods of low oil, natural gas liquids and natural gas prices to plug and abandon marginal
wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Chesapeake or any third-party
operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil, natural gas liquids and natural gas in
commercially economic quantities. This could result in termination of the portion of the royalty interest relating to the abandoned well or property, and Chesapeake
would have no obligation to drill a replacement well. The volatility of oil, natural gas liquids and natural gas prices also reduces the accuracy of target distributions to
trust unitholders. There can be no assurance that the trust’s hedging program will mitigate these risks. For a discussion of certain risks related to the trust’s hedging
arrangements, see “—The hedging arrangements for the trust will cover only a portion of the production attributable to the trust, such arrangements will limit the trust’s
ability to benefit from commodity price increases for hedged volumes, and such arrangements will be secured by the trust’s royalty interests in the Underlying
Properties and may require the trust to make cash payments in excess of its receipts” beginning on page 28.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.
The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the future
production estimated to be attributable to the trust’s royalty interests. The future production estimates are based on estimates of reserve quantities for the Underlying
Properties. See “The Underlying Properties—Oil, Natural Gas Liquids and Natural Gas Reserves” beginning on page 67 for a discussion of the method of allocating
proved reserves to the trust. It is not possible to measure underground accumulations of oil, natural gas liquids and natural gas in an exact way, and estimating reserves
is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could be materially less than estimated amounts. Petroleum engineers
are required to make subjective estimates of underground accumulations of oil, natural gas liquids and natural gas based on factors and assumptions that include:
•
historical production from the area compared with production rates from other producing areas;
•
oil, natural gas liquids and natural gas prices, production levels, btu content, production expenses, transportation costs, severance and
excise taxes and capital expenditures; and
•
the assumed effect of governmental regulation.
Changes in these assumptions or actual production expenses incurred and results of actual development could materially decrease reserve estimates.
Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of
production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. Most of the
Producing Wells have been operational for a relatively short period of time and estimated total reserves vary substantially from well to well and are not directly
correlated to perforated lateral length or completion technique. There can be no assurance that the data used in preparing these estimates can accurately predict future
production. The lack of operational history for horizontal wells in the Colony Granite Wash may also contribute to the inaccuracy of estimates of proved reserves. A
material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates, would have a material adverse effect on the
financial condition, results of operations and cash flows of the trust and would reduce cash distributions to trust unitholders.
22
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Index to Financial Statements
As with all horizontal drilling programs, there is a risk that some or all of a horizontal well could miss the target reservoir. As a result, the trust may not receive
the benefit, or any revenue from, some or all of the proved undeveloped reserves reflected in the reserve reports, notwithstanding the fact that Chesapeake has satisfied
its drilling obligation. See “Summary—The Development Wells” beginning on page 3.
Estimates of the target distributions to unitholders, subordination thresholds and incentive thresholds are based on assumptions that are inherently subjective and
are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ
materially from those estimated.
The estimates of target distributions to unitholders, subordination thresholds and incentive thresholds, as set forth in this prospectus, have been established by
Chesapeake, and Chesapeake has not received an opinion or report on such calculations from any independent accountants, financial advisers or engineers. Such
estimates are based on assumptions about drilling, production, oil, natural gas liquids and natural gas prices, hedging activities, capital expenditures, expenses, tax rates
and production tax credits under state law and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory
and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. For example, these estimates assume that oil, natural gas
liquids and natural gas production is sold at prices consistent with settled NYMEX pricing for July through October 2011, monthly NYMEX forward pricing as of
October 14, 2011 for the remainder of the period ending June 30, 2014 and assumed price increases after June 30, 2014 of 2.5% annually, capped at $120.00 per bbl of
oil (which cap would be reached in 2026) and $7.00 per mmbtu of natural gas (which cap would be reached in 2028); however, actual sales prices may not increase at
this rate or at all and may instead decline. Additionally, these estimates assume that the Development Wells will be drilled on Chesapeake’s current anticipated schedule
and the related Underlying Properties will achieve production volumes set forth in the reserve reports; however, the drilling of the Development Wells may be delayed
and actual production volumes may be significantly lower. Further, after wells are completed, production operations may be curtailed, delayed or terminated as a result
of a variety of risks and uncertainties, including those described above under “—Drilling for and producing oil, natural gas liquids and natural gas on the Underlying
Properties are high risk activities with many uncertainties that could delay the anticipated drilling schedule for the Development Wells and adversely affect future
production from the Underlying Properties. Any such delays or reductions in production could decrease cash available for distribution to unitholders” beginning on
page 20.
Furthermore, neither the target distribution nor the subordination threshold for each quarter during the subordination period necessarily represents the actual cash
distributions you will receive. To the extent actual production volumes or sales prices of oil, natural gas liquids and natural gas differ from the assumptions used to
generate the target distributions, the actual distributions you receive may be lower than the target distribution and the subordination threshold for the applicable quarter.
A cash distribution to trust unitholders below the target distribution amount or the subordination threshold may materially adversely affect the market price of the trust
units.
The subordination of certain trust units held by Chesapeake does not ensure that you will in fact receive any specified return on your investment in the trust.
Although Chesapeake will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a
distribution equal to the subordination threshold for such quarter (which is 20% below the target distribution level for the corresponding quarter), the subordinated units
constitute only a 25% interest in the trust, and this feature does not guarantee that common units will receive a distribution equal to the subordination threshold, or any
distribution at all. Additionally, the subordination period will terminate and the subordinated units will convert into common units at the end of the fourth full calendar
quarter following Chesapeake’s completion of its drilling obligation. Depending on the prices at which Chesapeake is able to sell volumes attributable to the trust, the
common units may receive a distribution that is below the subordination threshold.
23
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Index to Financial Statements
Quarterly cash distributions will be made by the trust based on the proceeds received by the trust pursuant to the royalty interests for the preceding calendar
quarter. If a quarterly cash distribution is lower than the target distribution amount or subordination threshold set forth in this prospectus for any quarter, the common
units will not be entitled to receive any additional distributions nor will the units be entitled to arrearages in any future quarter.
The historical and pro forma financial information included in this prospectus may not be representative of the trust’s future distributable income.
The historical financial information included in this prospectus is derived from Chesapeake’s historical financial statements for periods prior to the trust’s
formation or initial public offering. The historical financial information for the Underlying Properties included in this prospectus does not give effect to the terms and
conditions of the royalty interests and, as a result, does not reflect what the trust’s distributable income will be in the future.
In preparing the pro forma statements of distributable income included in this prospectus, Chesapeake has made adjustments to the historical pro forma financial
information for the Underlying Properties based upon currently available information and upon assumptions that Chesapeake and the trust believe are reasonable in
order to reflect, on a pro forma basis, the impact of the conveyance of the royalty interests to the trust and the other items discussed in the unaudited pro forma financial
statements and related notes. The estimates and assumptions used in the calculation of the pro forma financial information in this prospectus may be materially different
from the trust’s actual experience. Accordingly, the pro forma financial information included in this prospectus does not purport to represent what the trust’s
distributable income would actually have been had it been in operation during the periods presented or what the trust’s distributable income will be in the future, nor
does the pro forma financial information give effect to any events other than those discussed in the unaudited pro forma financial statements and related notes.
Chesapeake may not serve as the operator of as many of the Developmental Wells as it expects and Chesapeake will rely upon unaffiliated third parties, who may be
less qualified, to drill Development Wells where Chesapeake is not the operator.
Pursuant to the development agreement between Chesapeake and the trust, Chesapeake is obligated to drill, or cause to be drilled, 118 Development Wells in the
AMI. Although Chesapeake expects to operate approximately 93% of the Development Wells until the completion of its drilling obligation, another working interest
owner or a contract operator could serve as the operator for certain Development Wells. Chesapeake will rely upon these third-party operators to drill the Development
Wells where it is not the operator. The ability of third-party operators to help Chesapeake meet the drilling obligation will depend on those operators’ future financial
condition and economic performance and access to capital, which, in turn, will depend upon the supply and demand for oil, natural gas liquids and natural gas,
prevailing economic conditions and financial, business and other factors. The failure of an operator to adequately perform operations could reduce production from the
Underlying Properties and the cash available for distribution to trust unitholders. Chesapeake may be provided little or no notice by these operators that they are failing
to drill the Development Wells in accordance with pre-existing schedules.
Because Chesapeake does not have a majority working interest in the non-operated properties comprising the Underlying Properties, Chesapeake may not be
able to remove the operator in the event of poor or untimely performance. If the Development Wells take longer to be drilled than currently anticipated, this may delay
revenue earned from the production of oil, natural gas liquids and natural gas by such wells. The revenues distributable to the trust and the amount of cash distributable
to the trust unitholders would similarly be delayed.
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For those Development Wells where Chesapeake is the operator, Chesapeake may rely on third-party service providers to conduct the drilling operations.
Although Chesapeake owns substantial oilfield service assets, where Chesapeake is the operator of a Development Well, it may rely on third-party service
providers to perform the necessary drilling operations. The ability of third-party service providers to perform such drilling operations will depend on those service
providers’ financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and
natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations
could delay drilling or completion or reduce production from the Underlying Properties and the cash available for distribution to trust unitholders. If the Development
Wells take longer to be drilled and completed than currently anticipated, this may delay revenue earned from the production of oil, natural gas liquids and natural gas by
such wells. The revenues distributable to the trust and the amount of cash distributable to the trust unitholders would similarly be delayed.
Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of the Development Wells and result in a reduction in the
amount of cash available for distribution.
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas
industry can fluctuate significantly, often in correlation with oil, natural gas liquids and natural gas prices, causing periodic shortages. Historically, there have been
shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause
significant increases in costs for equipment, services and personnel. Higher oil, natural gas liquids and natural gas prices generally stimulate demand and result in
increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could
significantly hinder Chesapeake’s ability to perform the drilling obligation and delay completion of the Development Wells, which would reduce future distributions to
trust unitholders.
Due to the trust’s lack of industry and geographic diversification, adverse developments in the trust’s existing area of operation could adversely impact its financial
condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
The Underlying Properties will be operated for oil, natural gas liquids and natural gas production only and are focused exclusively in the Colony Granite Wash
in Washita County in western Oklahoma. This concentration could disproportionately expose the trust’s interests to operational and regulatory risk in that area. Due to
the lack of diversification in industry type and location of the trust’s interests, adverse developments in the oil, natural gas liquids and natural gas markets or the area of
the Underlying Properties, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled
maintenance, could have a significantly greater impact on the trust’s financial condition, results of operations and cash flows than if the trust’s royalty interests were
more diversified.
The generation of proceeds for distribution by the trust depends in part on access to and the operation of gathering, transportation and processing facilities. Any
limitation in the availability of those facilities could interfere with sales of oil, natural gas liquids and natural gas production from the Underlying Properties.
The amount of oil, natural gas liquids and natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to the
availability of gathering, transportation and processing facilities. Even where such facilities are available, services from such facilities are subject to curtailment in
certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil, natural gas
liquids and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery or physical damage
to the
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gathering system or transportation system. The curtailments may vary from a few days to several months. In many cases, Chesapeake or a third-party operator is
provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If Chesapeake or a third-party operator is forced to reduce
production due to such a curtailment, the revenues of the trust and the amount of cash distributions to the trust unitholders would similarly be reduced due to the
reduction of proceeds from the sale of production. Moreover, Chesapeake currently ships all of its natural gas production from the Underlying Properties to market
through one pipeline provider and sells all of its oil production from the Underlying Properties to one purchaser. Although Chesapeake currently does not have any
material production shut-in and does not shut in production on a routine basis as a result of lack of accessibility to transportation or lack of processing facilities, there
can be no assurance this will be the case in the future.
Some of the Development Wells on the Underlying Properties may be drilled in locations that currently are not serviced by gathering and transportation
pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, Chesapeake
may not be able to sell the production from certain Development Wells until the necessary gathering systems and/or transportation pipelines are constructed or until the
necessary transportation capacity on an interstate pipeline is obtained. Any delay in the procurement of additional transportation capacity would delay the receipt of any
proceeds that may be associated with production from the Development Wells.
The trust units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Underlying Properties.
The existence of title deficiencies with respect to the Underlying Properties could reduce the value or render properties worthless, thus adversely affecting the
distributions to unitholders. Chesapeake does not obtain title insurance covering oil, natural gas and mineral leaseholds. Additionally, undeveloped leasehold acreage
has greater risk of title defects than developed acreage.
Prior to the drilling of a Development Well, Chesapeake intends to obtain a drilling title opinion to identify defects in title to the leasehold. Frequently, as a
result of such examinations, certain curative work may be required to correct identified title defects, and such curative work entails time and expense. Chesapeake’s
inability or failure to cure title defects could render some locations undrillable or cause Chesapeake to lose its rights to some or all production from some of the
Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the trust units may be reduced.
The trust is passive in nature and will have no stockholder voting rights in Chesapeake, managerial, contractual or other ability to influence Chesapeake, or control
over the field operations of, sale of oil, natural gas liquids and natural gas from, or development of, the Underlying Properties.
Trust unitholders have no voting rights with respect to Chesapeake securities and will have no managerial, contractual or other ability to influence Chesapeake’s
activities or operations of the Underlying Properties. In addition, some of the Development Wells will be operated by third parties unrelated to Chesapeake. Such
third-party operators may not have the operational expertise of Chesapeake within the AMI. Oil and gas properties are typically managed pursuant to an operating
agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working
interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for
making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the
trustee nor the trust unitholders has any contractual ability to influence or control the field operations of, sale of oil, natural gas liquids and natural gas from, or future
development of, the Underlying Properties.
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The oil, natural gas liquids and natural gas reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those
reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets
and production.
The proceeds payable to the trust from the royalty interests are derived from the sale of the production of oil, natural gas liquids and natural gas from the
Underlying Properties. The oil, natural gas liquids and natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves
of oil, natural gas liquids and natural gas attributable to the Underlying Properties will decline over time. As a result, the quantity of oil, natural gas liquids and natural
gas produced from the Underlying Properties will decline over time.
Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The
timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas liquids and natural gas. With the exception of Chesapeake’s
commitment to drill the Development Wells, Chesapeake has no contractual obligation to the trust to make capital expenditures on the Underlying Properties in the
future. Furthermore, for properties on which Chesapeake is not designated as the operator, Chesapeake has no control over the timing or amount of those capital
expenditures. Chesapeake also has the right not to participate in the capital expenditures on properties for which it is not the operator, in which case Chesapeake and the
trust will not receive the production resulting from such capital expenditures. If Chesapeake or other operators of the wells to which the Underlying Properties relate do
not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by
Chesapeake or estimated in the reserve reports.
The trust agreement will provide that the trust’s business activities will generally be limited to owning the royalty interests and entering into the hedging
agreements and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the royalty interests. As a
result, the trust will not be permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the trust.
An increase in the differential between the price realized by Chesapeake for oil, natural gas liquids and natural gas produced from the Underlying Properties and
the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of
trust units.
The prices received for Chesapeake’s oil, natural gas liquids and natural gas production in Oklahoma usually fall below benchmark prices, such as NYMEX. The
difference between the price received and the benchmark price is called a differential. The amount of the differential will depend on a variety of factors, including
discounts based on the quality and location of hydrocarbons produced, btu content, post-production expenses and severance taxes. These factors can cause differentials
to be volatile from period to period. Chesapeake has little or no control over the factors that determine the amount of the differential, and cannot accurately predict
natural gas or crude oil differentials. Increases in the differential between the realized price of oil, natural gas liquids and natural gas and the benchmark price for oil,
natural gas liquids and natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of the trust units. For information
on the differentials assumed for purposes of preparing the target distributions, see “Target Distributions and Subordination and Incentive Thresholds—Significant
Assumptions Used to Calculate the Target Distributions” beginning on page 56.
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The amount of cash available for distribution by the trust will be reduced by post-production expenses and applicable taxes associated with the trust’s royalty
interests, trust expenses and incentive distributions payable to Chesapeake.
The royalty interests and the trust will bear certain costs and expenses that will reduce the amount of cash received by or available for distribution by the trust to
the holders of the trust units. These costs and expenses include the following:
•
the trust’s share of the expenses incurred by Chesapeake to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas
liquids and natural gas (excluding costs of marketing services provided by Chesapeake);
•
the trust’s share of applicable taxes on the oil, natural gas liquids and natural gas;
•
trust administrative expenses, including fees paid to the trustee and the Delaware trustee, the annual administrative services fee payable to Chesapeake,
tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees, costs associated with annual
and quarterly reports to unitholders and certain internal expenses of the trust incurred pursuant to the registration rights agreement; and
•
any amounts owed to counterparties under the trust’s hedging arrangements.
In addition, the amount of funds available for distribution to unitholders will be reduced by the amount of any cash reserves maintained by the trustee in respect
of anticipated future trust expenses.
Further, during the subordination period, Chesapeake will be entitled to receive a quarterly incentive distribution from the trust equal to 50% of the amount by
which cash available to be paid to all unitholders exceeds the incentive threshold for the applicable quarter. See “Target Distributions and Subordination and Incentive
Thresholds” beginning on page 50.
The amount of costs and expenses borne by the trust may vary materially from quarter to quarter. The extent by which the costs and expenses of the trust are
higher or lower in any quarter will directly decrease or increase the amount received by the trust and available for distribution to the unitholders. For a further summary
of post-production expenses and applicable taxes for the producing lives of the Producing Wells and Development Wells, see “The Underlying Properties” beginning on
page 63. Historical post-production expenses and taxes, however, may not be indicative of future post-production expenses and taxes.
The hedging arrangements for the trust will cover only a portion of the production attributable to the trust, such arrangements will limit the trust’s ability to benefit
from commodity price increases for hedged volumes, and such arrangements will be secured by the trust’s royalty interests in the Underlying Properties and may
require the trust to make cash payments in excess of its receipts.
The trust will be a party to oil and natural gas liquids hedging arrangements pursuant to which the trust will hedge approximately 50% of the expected oil and
natural gas liquids production and 37% of the trust’s expected revenues (based on NYMEX strip oil prices as of October 14, 2011) upon which the target distributions
from October 1, 2011 through September 30, 2015 are based. Estimated production of natural gas liquids will be hedged using a conversion ratio of one barrel of natural
gas liquids to 49.2% of a barrel of oil, which ratio may not be consistent with the market conversion ratio in the future. Except in limited circumstances involving the
restructuring of an existing hedge, the remaining estimated production of oil and natural gas liquids and all production of natural gas from October 1, 2011 through
September 30, 2015 will not be hedged and the trust will not have the ability to enter into additional hedges, terminate existing hedges or hedge production beyond
September 30, 2015. With respect to unhedged volumes and periods, the trust will not be protected against the price risks inherent in holding interests in oil, natural gas
liquids and natural gas, commodities that are frequently characterized by significant price volatility. Furthermore, while the use of hedging arrangements limits the
downside risk of price declines, they may also limit the trust’s ability to benefit from increases in oil and natural gas liquids prices above the hedge price on the portion
of the production attributable to the trust’s royalty interests that is hedged.
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Chesapeake will act as hedge manager to the trust pursuant to the administrative services agreement. In fulfilling its role as hedge manager, Chesapeake will not
act as a fiduciary for the trust, will have no affirmative duty to modify any of the trust’s hedges except as required by the hedging arrangements, and will have no
liability to the trust in connection with Chesapeake’s failure to modify, or any affirmative modification of, any of the trust’s hedges. Moreover, Chesapeake will be
indemnified by the trust for any actions it takes in this regard.
The trust’s receipt of any payments due to it based on the trust’s hedging arrangements depends upon the financial position of the hedge counterparties. If any of
the counterparties to the oil and natural gas liquids hedging arrangements were to default on their obligations to make payments under such contracts, the cash
distributions to the trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the trust during periods of
lower oil and natural gas liquids prices.
If actual production, over which the trust has no control, is below the amounts forecast in the reserve reports and oil or natural gas liquids prices rise, the hedging
arrangements entered into by the trust may result in the trust having to make cash payments under the hedging arrangements which could, in certain circumstances, be
significant. Swap contracts entered into between the trust and the hedge counterparties provide the trust with the right to receive from the hedge counterparties the
excess of the fixed price specified in the hedge contract over a floating market price, multiplied by the volume of production hedged. If the floating market price
exceeds the specified fixed price, the trust must pay its hedge counterparties this difference in price multiplied by the volume of production hedged, even if the
production attributable to the trust’s royalty interests is insufficient to cover the volume of production specified in the applicable hedging arrangements. Accordingly, if
the production attributable to the trust’s royalty interests is less than the volume hedged and the floating market price exceeds the specified fixed price, the trust will
have to make payments against which it will have insufficient offsetting cash receipts from the sale of production attributable to its royalty interests. If these payments
become too large, the trust’s liquidity and cash available for distribution may be adversely affected.
The trust’s and Chesapeake’s obligations to the counterparties under the hedging arrangements will be secured by the trust’s royalty interests in the Underlying
Properties. Subject to any applicable notice and cure periods, if, among other things, the trust or Chesapeake is in material default of the drilling, payment or reporting
obligations set forth in the hedging arrangements, or becomes subject to bankruptcy proceedings or the trust becomes subject to certain change of control transactions,
the hedging counterparties may foreclose on the lien on the trust’s royalty interests in the Underlying Properties. Following foreclosure by the hedging counterparties,
the counterparties may not be able to secure a replacement operator and any amounts recovered in such foreclosure action would not result in any distribution to the
trust unitholders. In addition, the trust’s hedging arrangements will contain a prohibition on the trust granting additional liens on any of its properties, other than
customary permitted liens and liens in favor of the trustees of the trust.
Please see “The Trust—Hedging Arrangements” beginning on page 47 for more details on the prices, production volumes and events of default associated with
the trust’s hedging arrangements.
The trustee may, under certain circumstances, sell the royalty interests and dissolve the trust; otherwise, the trust will begin to liquidate following the end of the
20-year period in which the trust owns the Term Royalties.
The royalty interests will be sold and the trust will be dissolved upon the occurrence of certain events described in “Description of the Trust
Agreement—Duration of the Trust; Sale of Royalty Interests” on page 87. For example, the trustee must sell the royalty interests if unitholders approve the sale or vote
to dissolve the trust. The trustee must also sell the royalty interests if cash available for distribution is less than $1.0 million in each of any four consecutive quarters.
The sale of all of the royalty interests will result in the dissolution of the trust. Upon the dissolution of the trust, the net proceeds of any such sale, after the payment of
trust liabilities, will be distributed to the trust unitholders pro rata and unitholders will not be entitled to receive any proceeds from the sale of production from the
Underlying Properties following such date. If none of these events occur, the trust will dissolve on the Termination Date.
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In connection with the dissolution of the trust on the Termination Date, the Term Royalties will automatically revert to Chesapeake, while the Perpetual
Royalties will be sold and the proceeds will be distributed to the unitholders (including Chesapeake to the extent of any trust units it owns) at the date the trust dissolves
or soon thereafter. The price received by the trust from any purchaser of the Perpetual Royalties will depend, among other things, on the prices of oil, natural gas liquids
and natural gas at that time. There can be no assurance that the prices of oil, natural gas liquids and natural gas will be at levels such that trust unitholders will receive
any particular amount of cash in return for the trust’s sale of the Perpetual Royalties.
Chesapeake will have a right of first refusal to purchase the Perpetual Royalties upon the dissolution of the trust, which may reduce the inclination of third
parties to place a bid, and thereby reduce the value received by the trust in a sale. If the trustee receives a bid from a proposed purchaser other than Chesapeake and
wants to sell all or part of the Perpetual Royalties to such third party, the trustee will be required to give notice to Chesapeake and identify the proposed purchaser and
proposed sale price, and other terms of the bid. See “The Trust” beginning on page 44.
There has been no public market for the common units and no independent appraisal of the value of the royalty interests has been performed.
The initial public offering price of the common units will be determined by negotiation among Chesapeake and the underwriters. Among the factors to be
considered in determining the initial public offering price, in addition to prevailing market conditions, will be current and historical oil, natural gas liquids and natural
gas prices, current and prospective conditions in the supply and demand for oil, natural gas liquids and natural gas, reserve and production quantities estimated for the
royalty interests and the trust’s cash distributions prospects. None of Chesapeake, the trust or the underwriters will obtain any independent appraisal or other opinion of
the value of the royalty interests other than the reserve reports prepared by Ryder Scott.
The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.
The business and affairs of the trust will be managed by the trustee. Your voting rights as a trust unitholder are more limited than those of stockholders of most
public corporations. For example, there is no requirement for annual meetings of trust unitholders, and the trust does not currently anticipate holding annual meetings.
Likewise, there is no requirement for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and
replaced by the holders of a majority of the outstanding trust units, excluding trust units held by Chesapeake, voting in person or by proxy at a special meeting of trust
unitholders at which a quorum is present called by either the trustee or the holders of not less than 10% of the outstanding trust units. As a result, it may be difficult for
public unitholders to remove or replace the trustee without the cooperation of holders of a substantial percentage of the outstanding trust units.
Trust unitholders have limited ability to enforce provisions of the royalty interests, and Chesapeake’s liability to the trust is limited.
The trust agreement permits the trustee and the trust to sue Chesapeake or any other future owner of the Underlying Properties to enforce the terms of the
conveyances creating the PDP Royalty Interest and the Development Royalty Interest. If the trustee does not take appropriate action to enforce provisions of these
conveyances, a trust unitholder’s recourse would be limited to bringing a lawsuit against the trust or the trustee to compel the trust or the trustee to take specified
actions. The trust agreement expressly limits a trust unitholder’s ability to directly sue Chesapeake or any other party other than the trustee. As a result, trust unitholders
will not be able to sue Chesapeake or any future owner of the Underlying Properties to enforce the trust’s rights under the conveyances. Furthermore, the royalty
interest conveyances prohibit recovery of certain types of damages, such as consequential and punitive damages, and provide that, except as set forth in the
conveyances, Chesapeake will not be liable to the trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good
faith and in accordance with the Reasonably Prudent Operator Standard and, to the fullest extent permitted by law, will owe no fiduciary duties to the trust or the
unitholders.
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Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private
corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
Chesapeake may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
After the closing of the offering, Chesapeake will hold an aggregate of 11,437,500 common units (assuming no exercise by the underwriters of their option to
purchase additional common units) and 11,437,500 subordinated units. All of the subordinated units will automatically convert into common units at the end of the
subordination period. Chesapeake has agreed not to sell any trust units for a period of 180 days after the date of this prospectus without the consent of Morgan
Stanley & Co. LLC and Raymond James & Associates, Inc. See “Underwriting” beginning on page 113. After such period, Chesapeake may sell trust units in the public
or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The trust has granted
registration rights to Chesapeake, which, if exercised, would facilitate sales of common units by Chesapeake to the public. See “Trust Units Eligible for Future
Sale—Registration Rights Agreement” on page 93.
Conflicts of interest could arise between Chesapeake and the trust.
Chesapeake could have interests that conflict with the interests of the trust and the trust unitholders. For example:
•
Notwithstanding its drilling obligation to the trust, Chesapeake’s interests may conflict with those of the trust and the trust unitholders in situations
involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, Chesapeake may abandon a well that
is no longer producing in paying quantities even though such well is still generating revenue for the trust unitholders. Subsequent to fulfilling its
drilling obligation, Chesapeake may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that
adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil, natural gas liquids and natural
gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.
•
Following the satisfaction of its drilling obligation to the trust, Chesapeake may, without the consent or approval of the trust unitholders, sell all or any
part of its retained interest in the Underlying Properties, if the Underlying Properties are sold subject to and burdened by the royalty interests. Although
Chesapeake must require any purchaser of its retained interest in the Underlying Properties to assume Chesapeake’s obligations with respect to those
properties, such sale may not be in the best interests of the trust and the trust unitholders. Any purchaser may lack Chesapeake’s experience in the
Colony Granite Wash or its creditworthiness. See “—After satisfying its drilling obligation to the trust, Chesapeake may sell all or a portion of its
retained interest in the Underlying Properties, subject to and burdened by the royalty interests; any such purchaser could have a weaker financial
position and/or be less experienced in oil, natural gas liquids and natural gas development and production than Chesapeake” beginning on page 32 and
“Description of the Royalty Interests—Additional Features of the Royalty Interests—Sale and Release of Underlying Properties” on page 81.
•
Following the satisfaction of its drilling obligation to the trust, Chesapeake may, without the consent or approval of the trust unitholders, require the
trust to release royalty interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by Chesapeake of a
portion of its retained interest in the Underlying Properties. Although these releases are conditioned upon the trust
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receiving an amount equal to the fair value to the trust of such royalty interests, the fair value received by the trust for such royalty interests may not fully
compensate the trust for the value of future production attributable to the royalty interests disposed of. See “Description of the Royalty
Interests—Additional Features of the Royalty Interests—Sale and Release of Underlying Properties” on page 81.
•
Chesapeake Midstream Partners provides Chesapeake with gathering, treatment and compression services with respect to natural gas and Chesapeake
Midstream Development provides Chesapeake with gathering services with respect to oil in the Colony Granite Wash. These Chesapeake affiliates are
expected to provide these services with respect to substantially all of the Underlying Properties. The amounts charged by Chesapeake Midstream
Partners and Chesapeake Midstream Development are post-production expenses that are deducted from trust revenues before making distributions to
trust unitholders. Chesapeake could favor the interests of these affiliates to the detriment of the trust and trust unitholders.
•
After expiration of a 180-day lock-up period, Chesapeake can sell its trust units regardless of the effects such sale may have on common unit prices or
on the trust itself. Additionally, once Chesapeake is allowed to vote its trust units, Chesapeake can vote its trust units in its sole discretion.
In addition, Chesapeake has agreed that, if at any time the trust’s cash on hand (including available cash reserves) is not sufficient to pay the trust’s ordinary
course expenses as they become due, Chesapeake will lend funds to the trust necessary to pay such expenses. Any such loan will be on an unsecured basis, and the
terms of such loan will be substantially the same as those which would be obtained in an arms’ length transaction between Chesapeake and an unaffiliated third party. If
Chesapeake provides such funds to the trust, it would become a creditor of the trust and its interests as a creditor could conflict with the interests of unitholders.
After satisfying its drilling obligation to the trust, Chesapeake may sell all or a portion of its retained interest in the Underlying Properties, subject to and burdened
by the royalty interests; any such purchaser could have a weaker financial position and/or be less experienced in oil, natural gas liquids and natural gas
development and production than Chesapeake.
You will not be entitled to vote on any sale by Chesapeake of its retained interest in the Underlying Properties and the trust will not receive any proceeds from
any such sale. The purchaser would be responsible for all of Chesapeake’s obligations relating to the royalty interests on the portion of the Underlying Properties sold,
including Chesapeake’s obligation to operate the Underlying Properties sold in accordance with the Reasonably Prudent Operator Standard and Chesapeake’s true-up
obligations with respect to the Underlying Properties sold, and Chesapeake would have no continuing obligation to the trust for those properties. Additionally, after
satisfying its drilling obligation, Chesapeake may enter into farmout or participation arrangements with respect to the wells burdened by the trust’s royalty interests.
Any purchaser, farmout counterparty or participating partner could have a weaker financial position and/or be less experienced in oil, natural gas liquids and natural gas
development and production in the Colony Granite Wash than Chesapeake, which could result in a decrease in production from the Underlying Properties sold and a
corresponding decrease in cash available for distribution to the trust’s unitholders. Additionally, in the event that Chesapeake enters into such a farmout or participation
agreement, the royalty interest will not burden any interests that the counterparty earns under such an agreement.
Chesapeake’s ability to satisfy its obligations to the trust depends on its financial position, and in the event of a default by Chesapeake in its obligation to drill the
Development Wells or Chesapeake’s bankruptcy, it may be expensive and time-consuming for the trust to exercise its remedies and the trust may be treated as an
unsecured creditor of Chesapeake.
Pursuant to the terms of the development agreement, Chesapeake will be obligated to drill, or cause to be drilled, the Development Wells at its own expense.
Chesapeake expects to operate approximately 93% of such wells until the completion of its drilling obligation. Chesapeake also currently operates 94% of the
Producing Wells. The conveyances provide that Chesapeake will be obligated to market, or cause to be marketed, the oil,
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natural gas liquids and natural gas production related to the Underlying Properties. Due to the trust’s reliance on Chesapeake to fulfill these obligations, the value of the
trust’s royalty interests and its ultimate cash available for distribution will be highly dependent on Chesapeake’s performance.
Chesapeake’s ability to perform these obligations will depend on its future financial condition and economic performance and access to capital, which in turn
will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors, many of
which are beyond Chesapeake’s control. See “Chesapeake Energy Corporation” on page 43 and “Where You Can Find More Information” beginning on page 117 for
additional information relating to Chesapeake.
If Chesapeake were to default on its obligation to drill the Development Wells, the trust would be able to foreclose on the Drilling Support Lien to the extent of
Chesapeake’s remaining interests in the undeveloped portions of the AMI, file a lawsuit to collect money damages from Chesapeake and pursue other available legal
remedies against Chesapeake. However, the trust is not permitted to obtain specific performance from Chesapeake of its drilling obligation, and the maximum amount
the trust can recover in a foreclosure or other action is limited to approximately $262.7 million, which is the estimated amount of the trust’s share of the costs of drilling
the Development Wells and is not indicative of the total costs that will actually be incurred in drilling those wells. The maximum amount that the trust can recover will
be reduced proportionately as each Development Well is completed and released from the Drilling Support Lien and will not be adjusted for general inflation or
inflation in oilfield service costs. There can be no assurance that the value of Chesapeake’s interests in the undeveloped portions of the AMI secured by the Drilling
Support Lien will be equal to the amount recoverable at any given time, and such interests may be worth considerably less. The process of foreclosing on such collateral
may be expensive and time-consuming and delay the drilling and completion of the Development Wells; such delays and expenses would reduce trust distributions by
reducing the amount of proceeds available for distribution and may result in the loss of acreage due to leasehold expirations. Any amounts actually recovered in a
foreclosure action would be applied to completion of Chesapeake’s drilling obligation, would not result in any distribution to the trust unitholders and may be
insufficient to drill the number of wells needed for the trust to realize the full value of the Development Royalty Interest. Furthermore, the trust would have to seek a
new party to perform the drilling and operations of the wells. The trust may not be able to find a replacement driller or operator, and it may not be able to enter into a
new agreement with such replacement party on favorable terms within a reasonable period of time. As long as the trust’s royalty interests are pledged as collateral to the
trust’s hedge counterparties, the trust’s arranging for a replacement driller or operator may be more difficult or impossible. In such an event, the production from the
trust’s properties would decline and such decline may trigger a foreclosure on the trust’s royalty interests by the hedging counterparties. The possibility of this
foreclosure could deter the trust from exercising its right to foreclose on the Drilling Support Lien.
The proceeds of the royalty interests may be commingled, for a period of time, with proceeds of Chesapeake’s retained interest in the Underlying Properties, and
Chesapeake will not be required to maintain a segregated account for proceeds payable to the trust. In the event of a collection proceeding, it is possible that the trust
may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against Chesapeake’s
retained interest, be able to assert claims to the proceeds that should be delivered to the trust. In addition, during any bankruptcy of Chesapeake, it is possible that
payments of the royalties may be delayed or deferred. During the pendency of any Chesapeake bankruptcy proceedings, the trust’s ability to foreclose on the Drilling
Support Lien, and the ability to collect cash payments being held in Chesapeake’s accounts that are attributable to production from the trust properties, and even its
ability to demand any of these remedies, may be stayed or prohibited by the bankruptcy proceeding. Delay in realizing on the collateral for the Drilling Support Lien is
possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new
agreement with another driller or operator. If the trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same
levels of production or sell oil, natural gas liquids and natural gas at the same prices as Chesapeake was able to achieve.
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In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that will convey the royalty interests to the trust, the trust could lose
the value of all of the royalty interests if a bankruptcy court were to hold that the royalty interests constitute an asset of the bankruptcy estate. Chesapeake and the trust
believe that the royalty interests would not be included in any such bankruptcy estate because the recordation of the conveyance of the royalty interests in the
appropriate real property records in Oklahoma will constitute the conveyance of fully vested real property interests under Oklahoma law or interests in hydrocarbons in
place or to be produced under Oklahoma law. Oklahoma law, however, is not entirely clear as to whether an overriding royalty interest is a real property interest. While
the Oklahoma Supreme Court has recently held that royalty interests are real property interests, such cases did not expressly overturn prior Oklahoma Supreme Court
cases holding that an overriding royalty interest was not necessarily a real property interest. In the event of a bankruptcy of Chesapeake or the wholly owned
subsidiaries of Chesapeake that will convey the royalty interests to the trust, if a bankruptcy court held that (a) the royalty interests did not constitute fully vested real
property interests or interests in hydrocarbons in place or to be produced or (b) the royalty interests were not otherwise eligible to be excluded from the bankruptcy
estate under federal bankruptcy law, the royalty interests may be treated as unsecured claims of the trust against Chesapeake. If that were the case, creditors of
Chesapeake would be able to claim the royalty interests as an asset of the bankruptcy estate to be sold to satisfy obligations to them and the trust could lose the entire
value of the royalty interests to senior creditors of Chesapeake.
Oil and gas drilling and producing operations can be hazardous and may expose Chesapeake to liabilities, including environmental liabilities.
Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures,
uncontrollable flows of natural gas, oil, brine or well fluids and other environmental hazards and risks. Chesapeake’s drilling operations involve risks from high
pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. Some of these risks or hazards could materially and adversely
affect Chesapeake’s revenues and expenses by reducing or shutting in production from wells or otherwise negatively impacting the projected economic performance of
its prospects. A temporary or permanent halt of the production and sale of oil, natural gas liquids and natural gas at any of the Underlying Properties could also reduce
trust distributions by reducing the amount of proceeds available for distribution.
Additionally, if any of these risks occurs, Chesapeake could sustain substantial losses as a result of:
•
injury or loss of life;
•
severe damage to or destruction of property, natural resources or equipment;
•
pollution or other environmental damage;
•
clean-up responsibilities;
•
regulatory investigations and administrative, civil and criminal penalties; and
•
injunctions resulting in limitation or suspension of operations.
There is also inherent risk of incurring significant environmental costs and liabilities in oil and gas operations due to the generation, handling and disposal of
materials, including wastes and petroleum hydrocarbons. Chesapeake may incur joint and several, strict liability under applicable U.S. federal and state environmental
laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from its leased or owned properties, some of which have
been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under its control. For non-operated properties,
Chesapeake is dependent on the operator for operational and regulatory compliance. See “The Underlying Properties—Regulation” beginning on page 75 for a
discussion of environmental regulation applicable to Chesapeake.
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Chesapeake maintains policies of insurance that it believes are customary in the industry, including a $75 million control of well policy that insures against
certain sudden and accidental risks associated with drilling, completing (including hydraulic fracturing) and operating its wells. Chesapeake also carries a $425 million
comprehensive general liability umbrella policy and a $150 million pollution liability policy. Chesapeake’s insurance policies provide for customary deductibles
(generally ranging from $1.0 million to $5.0 million), and there is no assurance that these policies will provide complete coverage against all operational risks. In
addition, these policies do not cover penalties or fines that may be assessed by a governmental authority. If Chesapeake experiences any of the problems described
above and its insurance policies do not provide adequate coverage, its ability to conduct operations and perform its obligations to the trust could be adversely affected.
Moreover, these policies also cover properties and operations of Chesapeake unrelated to the Underlying Properties and the trust. To the extent proceeds from such
policies are used to cover losses in Chesapeake’s other operations, such coverage may not be available to cover losses relating to the trust. Finally, we are not obligated
to the trust to maintain any particular types or amounts of insurance, and insurance may not be commercially available at the levels indicated above at all times during
the life of the trust. If a well is damaged, Chesapeake would have no obligation to drill a replacement well or otherwise compensate the trust for the loss. The trust will
have no insurance or indemnification to protect against losses or delays in receiving proceeds from such events.
Potential legislative and regulatory actions could increase Chesapeake’s costs, reduce its revenue and cash flow from the sale of oil, natural gas liquids and natural
gas, reduce its liquidity or otherwise alter the way it conducts business.
The activities of exploration and production companies operating in the United States are subject to extensive regulation at the federal, state and local levels.
Changes to existing laws and regulations or new laws and regulations such as those described below could, if adopted, have an adverse effect on Chesapeake’s business
and could reduce cash received by or available for distribution from the trust.
Federal Taxation of Producers of Oil and Natural Gas
Federal budget proposals would potentially increase and accelerate the payment of federal income taxes of producers of oil and natural gas. Proposals that would
significantly affect Chesapeake would repeal the expensing of intangible drilling costs, the percentage depletion allowance and lengthen the amortization period of
geological and geophysical expenses. These changes, if enacted, will make it more costly for Chesapeake to explore for and develop its oil and natural gas resources.
OTC Derivatives Regulation
In July 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains measures
aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. The trust will engage in
hedging activities to manage the risk of low commodity prices and to predict with greater certainty the cash flow from its hedged production. The Dodd-Frank Act and
the rules and regulations promulgated thereunder could reduce trading positions in the energy futures markets. Such changes could materially reduce hedging
opportunities for the trust and negatively affect its revenues and cash flow during periods of low commodity prices.
Hydraulic Fracturing
Hydraulic fracturing, the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped
under high pressure into the formation, is currently used in completing greater than 90% of all oil and natural gas wells drilled in the United States. While hydraulic
fracturing is typically regulated by state oil and gas commissions, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels
under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents for permitting authorities and
the industry on the process for obtaining a permit for hydraulic fracturing involving diesel fuel. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, with results of the
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study anticipated to be available by late 2012. Also, for the second consecutive session, legislation has been introduced in Congress to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Chesapeake cannot predict whether additional hydraulic fracturing federal,
state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or
permitting requirements were imposed through the adoption of new laws and regulations, Chesapeake’s operations with respect to the Underlying Properties could be
subject to delays, increased operating and compliance costs and process prohibitions. Restrictions on hydraulic fracturing could also reduce the amount of oil, natural
gas liquids and natural gas that Chesapeake is ultimately able to produce in commercial quantities from the Underlying Properties.
Climate Change
Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations
governing or restricting the emission of greenhouse gases from stationary sources such as Chesapeake’s equipment and operations. At the federal level, the EPA has
already made findings and issued regulations that require Chesapeake to establish and report an inventory of greenhouse gas emissions and that could lead to the
imposition of restrictions on greenhouse gas emissions from stationary sources used in oil and gas operations. Legislative and regulatory proposals for restricting
greenhouse gas emissions or otherwise addressing climate change could require Chesapeake to incur additional operating costs and could adversely affect demand for
oil, natural gas liquids and natural gas. The potential increase in operating costs could include new or increased costs to obtain permits, operate and maintain equipment
and facilities, install new emission controls on equipment and facilities, acquire allowances to authorize greenhouse gas emissions, pay taxes related to our greenhouse
gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce
demand for oil, natural gas liquids and natural gas.
For more information on environmental and regulatory risks, please read “The Underlying Properties—Regulation” beginning on page 75.
The trust will be subject to the requirements of the Sarbanes-Oxley Act of 2002, which may impose cost and operating challenges on it.
The trust will be subject to certain of the requirements of the Sarbanes-Oxley Act of 2002 which will require, among other things, maintenance by the trust of,
and reports regarding the effectiveness of, a system of internal control over financial reporting. Complying with these requirements may pose operational challenges and
may cause the trust to incur unanticipated expenses. Any failure by the trust to comply with these requirements could lead to a loss of public confidence in the trust’s
internal controls and in the accuracy of the trust’s publicly reported results.
Tax Risks Related to the Units
The trust’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the IRS were to treat the trust as a corporation for U.S.
federal income tax purposes or the trust were subjected to state or local entity level tax, then its cash available for distribution to unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in the trust units depends largely on the trust being treated as a partnership for U.S. federal income
tax purposes. The trust has not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter affecting it.
It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the trust, to be treated as a corporation for U.S. federal
income tax purposes. Although the trust does not believe based upon its current activities that such treatment is applicable to it, a change in current law could cause it to
be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to taxation as an entity.
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If the trust were treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate,
which is currently a maximum of 35%, and would likely be required to pay state income tax on its taxable income at the corporate tax rate in Oklahoma. Distributions
to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you without first being
subjected to taxation at the entity level. Because a tax would be imposed upon the trust as a corporation, its cash available for distribution to you would be substantially
reduced. Therefore, treatment of the trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the trust unitholders,
likely causing a substantial reduction in the value of the trust units.
The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the trust to taxation as a corporation or
otherwise subjects it to entity-level taxation for U.S. federal, state or local income tax purposes, the subordination threshold amounts and the target distribution amounts
may be adjusted to reflect the impact of that law on the trust.
The U.S. federal income tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the
trust takes with respect to the Development Royalty Interest could affect the amount, timing and character of income, gain or loss relating to an investment in trust
units.
The U.S. federal income tax laws and precedents applicable to the tax treatment of royalty interests in wells that will be drilled in the future are not well
established. As a result, the tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the
trust takes with respect to the Development Royalty Interest could negatively affect the amount, timing and character of income, gain or loss relating to a unitholder’s
investment in trust units, which could increase or accelerate the amount of federal income tax payable on a unitholder’s share of the trust’s income. Please read “U.S.
Federal Income Tax Considerations—Tax Classification of the PDP Royalty Interest and the Development Royalty Interest” beginning on page 98.
The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
The Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual
having adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to an additional “Medicare tax” equal generally to 3.8% of
the lesser of such excess or the individual’s net investment income, which appears to include interest income and royalty income derived from investments such as the
trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the
highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. It
has been assumed that the effective rate of production tax on the oil, natural gas liquids and natural gas attributable to the trust will be approximately 2.0% for the first
four years of production for each well, and approximately 7.0% thereafter. Moreover, these rates are subject to change by new legislation at any time.
Current law may change so as to cause the trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the trust to entity-level
taxation. Specifically, the present U.S. federal income tax treatment of publicly traded partnerships, including the trust, or an investment in the trust units may be
modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed in the past that would have
eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to the trust as it was proposed, it could
be reintroduced in a manner that does apply to the trust. Any such legislation would likely also affect the trust tax treatment for state tax purposes.
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The trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the tax positions the trust takes, the value of
the trust units may be adversely affected, the cost of any IRS contest will reduce the trust’s cash available for distribution and income, gain, loss and deduction may
be reallocated among trust unitholders.
If the IRS contests any of the U.S. federal income tax positions the trust takes, the value of the trust units may be adversely affected because the cost of any IRS
contest will reduce the trust’s cash available for distribution and income, gain, loss and deduction may be reallocated among trust unitholders. For example, the trust
will generally prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each quarter based upon the record ownership
of the trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular trust unit is transferred. Although simplifying conventions
are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of these methods may not be
permitted under existing Treasury Regulations.
The trust has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting
the trust. The IRS may adopt positions that differ from the conclusions of the trust’s counsel expressed in this prospectus or from the positions the trust takes. It may be
necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the trust’s counsel or the positions the trust takes. A
court may not agree with some or all of the conclusions of the trust’s counsel or positions the trust takes. Any contest with the IRS may materially and adversely impact
the market for the trust units and the price at which they trade. In addition, the trust’s costs of any contest with the IRS will be borne indirectly by the trust unitholders
because the costs will reduce the trust’s cash available for distribution.
You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.
Because the trust unitholders will be treated as partners to whom the trust will allocate taxable income that could be different in amount than the cash the trust
distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the trust’s taxable income even if you
receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your share of the trust’s taxable income or even equal to the
actual tax liability that results from that income.
Tax gain or loss on the disposition of the trust units could be more or less than expected.
If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. Because
distributions in excess of your allocable share of the trust’s net taxable income decrease your tax basis in your trust units, the amount, if any, of such prior excess
distributions with respect to the trust units you sell will, in effect, become taxable income to you if you sell such trust units at a price greater than your tax basis in those
trust units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may
be taxed as ordinary income due to potential recapture items, including depletion recapture. Please read “U.S. Federal Income Tax Considerations—Disposition of Trust
Units—Recognition of Gain or Loss” beginning on page 106 for a further discussion of the foregoing.
The ownership and disposition of trust units by non-U.S. persons may result in adverse tax consequences to them.
Investment in trust units by non-U.S. persons raises issues unique to them. For example, distributions to non-U.S. persons will be reduced by withholding taxes
at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the trust’s taxable
income or proceeds from the sale of trust units. If you are a non-U.S. person, you should consult a tax advisor before investing in the trust units.
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The trust will treat each purchaser of trust units as having the same economic attributes without regard to the actual trust units purchased. The IRS may challenge
this treatment, which could adversely affect the value of the trust units.
Due to a number of factors, including the trust’s inability to match transferors and transferees of trust units, the trust will adopt positions that may not conform to
all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in trust units. It also
could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of the trust units or result
in audit adjustments to your tax returns. Please read “U.S. Federal Income Tax Considerations—Tax Consequences of Trust Unit Ownership—Section 754 Election” on
page 105.
The trust will prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each quarter based upon the record
ownership of the trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular trust unit is transferred. The IRS may
challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.
The trust will generally prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units based upon the record
ownership of the trust units on the quarterly record date in such quarter instead of on the basis of the date a particular trust unit is transferred.
The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, the trust’s counsel is unable to opine as to the
validity of this method. If the IRS were to challenge the trust’s proration method, the trust may be required to change its allocation of items of income, gain, loss and
deduction among the trust unitholders and the costs to the trust of implementing and reporting under any such changed method may be significant. Please read “U.S.
Federal Income Tax Considerations—Disposition of Trust Units—Allocations Between Transferors and Transferees” on page 107.
A trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of those trust units. If so,
he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the
disposition.
Because a trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of the loaned
trust units, he may no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the trust’s income, gain, loss or deduction with
respect to those trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those trust units could be fully taxable as
ordinary income. The trust’s counsel has not rendered an opinion regarding the treatment of a unitholder where trust units are loaned to a short seller to cover a short
sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to
modify any applicable brokerage account agreements to prohibit their brokers from loaning their trust units.
The trust will adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the trust unitholders. The IRS may challenge
this treatment, which could adversely affect the value of the trust units.
The U.S. federal income tax consequences of the ownership and disposition of trust units will depend in part on the trust’s estimates of the relative fair market
values, and the initial tax bases of the trust’s assets. Although the trust may from time to time consult with professional appraisers regarding valuation matters, the trust
will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS
or the courts. If the estimates of fair market value or basis
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are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust
unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
The sale or exchange of 50% or more of the trust’s capital and profits interests during any twelve-month period will result in the technical termination of the trust
for U.S. federal income tax purposes.
The trust will be considered to have technically terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total
interests in its capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same trust
unit within any 12 month period will be counted only once. The trust’s termination would, among other things, result in the closing of its taxable year for all trust
unitholders, which would result in the trust filing two tax returns (and the trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has
recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other
things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder
reporting on a taxable year other than a calendar year ending December 31, the closing of the trust’s taxable year may also result in more than 12 months of the trust’s
taxable income being includable in his taxable income for the year of termination. A technical termination would not affect the trust’s classification as a partnership for
U.S. federal income tax purposes, but instead, the trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the trust must make new
tax elections and could be subject to penalties if the trust is unable to determine that a technical termination occurred.
You may be subject to state and local taxes and return filing requirements in jurisdictions where you do not live as a result of investing in trust units.
In addition to federal income taxes, trust unitholders will likely be subject to other taxes, including Oklahoma state income taxes, even if they do not live in
Oklahoma. You will likely be required to file Oklahoma state income tax returns and pay Oklahoma state income tax. Further, you may be subject to penalties for
failure to comply with those requirements. It is each trust unitholder’s responsibility to file all U.S. federal, state, local and non-U.S. tax returns.
Certain U.S. federal income tax preferences currently available with respect to oil, natural gas liquids and natural gas production may be eliminated as a result of
future legislation.
Among the proposed changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 is the elimination of certain key U.S. federal income tax
preferences relating to oil, natural gas liquids and natural gas exploration and production. The President’s budget proposes to eliminate certain tax preferences
applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion
with respect to wells, including interests such as the Perpetual Royalties, in which case only cost depletion would be available.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This prospectus and the documents incorporated by reference contain forward-looking statements. Such forward-looking statements are based on assumptions
and beliefs that the trust and Chesapeake believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed
facts and actual results can be material, depending upon the circumstances. Where the trust or Chesapeake expresses an expectation or belief as to future results, that
expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. It cannot be assured, however, that the stated expectation
or belief will occur or be achieved or accomplished. All statements other than statements of historical facts included or incorporated by reference in this prospectus,
including, without limitation, statements regarding the proved oil, natural gas liquids and natural gas reserves associated with the Underlying Properties, the trust’s or
Chesapeake’s future financial position, business strategy, budgets, pending acquisitions, recent acquisitions and divestitures, project costs and plans and objectives for
future operations, including the information under the heading “Target Distributions and Subordination and Incentive Thresholds” beginning on page 50, statements
pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements are
forward-looking statements.
The words “estimate,” “assume, “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should”
and “intend” and similar expressions will generally identify forward-looking statements. Forward-looking statements, whether written or oral, are expressly qualified by
these cautionary statements and any other cautionary statements that may accompany those statements. In addition, neither the trust nor Chesapeake undertakes an
obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this prospectus.
With this in mind, you should consider the risks discussed under the heading “Risk Factors” beginning on page 20, as well as those contained in Chesapeake’s
Annual Report on Form 10-K for the year ended December 31, 2010, and other disclosures about Chesapeake, the trust and the Underlying Properties that are included
in or incorporated by reference into this prospectus.
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USE OF PROCEEDS
The trust is offering all of the common units to be sold in this offering. Assuming no exercise of the underwriters’ option to purchase additional common units
and an initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover page of this prospectus), the estimated net proceeds
of this offering will be approximately $426.3 million, after deducting underwriting discounts and commissions, the structuring fee and estimated offering expenses. The
trust will deliver all of the net proceeds to a wholly owned subsidiary of Chesapeake, as consideration for the conveyance of the Term Royalties and as partial
consideration for the conveyance of the Perpetual Royalties. The following table summarizes the trust’s sources and uses of funds associated with this offering (based
on the foregoing assumptions):
Sources:
Proceeds to trust from sale of common units in this offering
$ 457,500,000
Total
$ 457,500,000
Uses:
Underwriting discounts and commissions
Structuring fee paid to Morgan Stanley & Co. LLC and Raymond James & Associates, Inc.
Offering expenses
Partial consideration for the purchase of royalty interests from Chesapeake
Total
$ 26,306,250
2,287,500
2,571,922
426,334,328
$ 457,500,000
At the initial closing, 3,431,250 common units that may be issued to Chesapeake will be retained by the trust to satisfy (if necessary) the option to purchase
additional common units granted to the underwriters. If the underwriters exercise their option to purchase additional common units, the trust will sell to the underwriters
such number of the retained units as is necessary to satisfy the option to purchase additional common units, and will then deliver the net proceeds of such sale, together
with any remaining unsold units, to Chesapeake as partial consideration for the conveyance of the Perpetual Royalties. If the option to purchase additional common
units is not exercised by the underwriters, the retained units will be delivered to Chesapeake as partial consideration for the conveyance of the Perpetual Royalties
promptly following the 30th day after the date of this prospectus.
Chesapeake intends to use any proceeds it receives from the sale of the royalty interests to the trust to repay borrowings under its credit facility. Chesapeake may
re-borrow amounts under its credit facility from time to time and does so for general corporate purposes, including capital expenditures for land, drilling and other costs.
Affiliates of certain of the underwriters are lenders under Chesapeake’s credit facility and, in that respect, will receive a substantial portion of the proceeds from this
offering through the repayment of borrowings outstanding under the facility. See “Underwriting” beginning on page 113. Chesapeake’s credit facility matures on
December 2, 2015 and, as of September 30, 2011, the weighted average interest rate applicable to borrowings under the credit facility was 1.98%. Borrowings under the
credit facility in the past year were incurred by Chesapeake for general corporate purposes, including capital expenditures for land, drilling and other costs.
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CHESAPEAKE ENERGY CORPORATION
Chesapeake is the second-largest producer of natural gas, is among the top 15 producers of oil and natural gas liquids and is the most active driller, based on rig
count, of new oil and natural gas wells in the U.S. Chesapeake’s operations are focused on discovering and developing unconventional natural gas and oil fields onshore
in the U.S. Chesapeake owns leading positions in the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and in the Granite Wash, Cleveland,
Tonkawa, Mississippian, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Frontier, Codell, Bakken/Three Forks and Utica unconventional liquids
plays. It has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. As of June 30, 2011, Chesapeake
had total assets of approximately $36.7 billion and total estimated net proved reserves of 16.5 tcfe. Chesapeake has approximately 61,100 net acres leased in the Colony
Granite Wash and as of June 30, 2011, Chesapeake was operating nine rigs in the Colony Granite Wash.
Chesapeake has not previously sponsored a royalty trust.
Chesapeake’s principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and its telephone number is
(405) 848-8000. Chesapeake’s website is www.chk.com ; however, the information contained on Chesapeake’s website is not incorporated by reference into this
prospectus.
The trust units do not represent interests in or obligations of Chesapeake.
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THE TRUST
The trust is a statutory trust created under the Delaware Statutory Trust Act in June 2011. The business and affairs of the trust will be managed by The Bank of
New York Mellon Trust Company, N.A., as trustee. In addition, The Corporation Trust Company will act as Delaware trustee of the trust. The Delaware trustee will
have only minimal rights and duties as are necessary to satisfy the requirements of having a trustee in Delaware who will accept service of process on the trust under the
Delaware Statutory Trust Act. Although Chesapeake will operate most of the Underlying Properties, Chesapeake will have no ability to manage or influence the
operations of the trust (except through its limited voting rights as a holder of trust units) and, to the fullest extent permitted by law, will owe no fiduciary duties to the
trust or the unitholders.
The trustee can authorize the trust to borrow money to pay trust expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from
the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if
the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short-term investments with the funds distributed to the trust.
The trustee may also hold funds awaiting distribution in a non-interest bearing account. The trustee has no current plans to authorize the trust to borrow money.
The trust will be responsible for paying all legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket expenses incurred by
or at the direction of the trustee or the Delaware trustee, including tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and
transfer agent fees. The trust will also be responsible for any payment obligations under the hedging arrangements and for paying other expenses incurred as a result of
being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, and this offering. Trust administrative expenses are
anticipated to aggregate approximately $1.0 million per year, although such costs could be greater or less depending on future events that cannot be predicted. Included
in the annual estimate is an annual administrative fee of $175,000 for the trustee, which may be adjusted beginning on January 1, 2015 as provided in the trust
agreement, an annual administrative fee of $2,000 for the Delaware trustee and an annual fee of $200,000 payable to Chesapeake pursuant to the terms of the
administrative services agreement. The trustee will also receive a one-time acceptance fee of $10,000. These costs will be deducted from revenues by the trust before
distributions are made to trust unitholders. The trustee intends to withhold $1.0 million from the first distribution to establish an initial cash reserve available for trust
expenses. Additional cash reserves may also be established from time to time as determined by the trustee to pay future expenses of the trust.
Formation Transactions
At or prior to the closing of the offering, Chesapeake will convey to the trust a 90% royalty interest in the Producing Wells and a 50% royalty interest in the
Development Wells. The conveyance will be effective as of July 1, 2011.
The 90% royalty interest in the Producing Wells will consist of a term royalty interest entitling the trust to receive 45% of the proceeds from the sale of oil,
natural gas liquids and natural gas production attributable to Chesapeake’s net revenue interest in the Producing Wells (after deducting post-production expenses and
any applicable taxes) for a period of 20 years commencing on July 1, 2011 (the “Term PDP Royalty”) and a perpetual royalty interest entitling the trust to receive 45%
of the proceeds from the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake’s net revenue interest in the Producing Wells (after
deducting post-production expenses and any applicable taxes) (the “Perpetual PDP Royalty”).
The 50% royalty interest in the Development Wells will consist of a term royalty interest entitling the trust to receive 25% of the proceeds from the sale of the
production of oil, natural gas liquids and natural gas attributable to Chesapeake’s net revenue interest in the Development Wells (after deducting post-production
expenses and any applicable taxes) for a period of 20 years commencing on July 1, 2011 (the “Term Development Royalty”) and a perpetual royalty interest entitling
the trust to receive 25% of the proceeds from
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the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake’s net revenue interest in the Development Wells (after deducting
post-production expenses and any applicable taxes) (the “Perpetual Development Royalty”).
The Term PDP Royalty and the Term Development Royalty are collectively referred to as the “Term Royalties,” and the Perpetual PDP Royalty and the
Perpetual Development Royalty are collectively referred to as the “Perpetual Royalties.” The Perpetual Royalties will be conveyed directly from Chesapeake to the
trust. The Term Royalties will be conveyed to a wholly owned subsidiary of Chesapeake in exchange for a demand note, such subsidiary will convey the Term
Royalties to the trust in exchange for a portion of the net proceeds of this offering in an amount equal to such demand note and such subsidiary will use such proceeds
to repay the demand note. In exchange for the Perpetual Royalties, the trust will issue to Chesapeake 11,437,500 common units and 11,437,500 subordinated units and
will also deliver to Chesapeake the balance of the net proceeds of the offering. See “Use of Proceeds” on page 42.
The trust will retain 3,431,250 common units at the initial closing, to be used to satisfy (if necessary) the option to purchase additional common units granted to
the underwriters. If the underwriters exercise their option to purchase additional common units, the trust will sell to the underwriters such number of the retained units
as is necessary to satisfy the option to purchase additional common units, and will then deliver the net proceeds of such sale, together with any remaining unsold units,
to Chesapeake as partial consideration for the conveyance of the Perpetual Royalties. If the underwriters do not exercise the option to purchase additional common
units, the retained units will be delivered to Chesapeake as partial consideration for the conveyance of the Perpetual Royalties, promptly following the 30th day after the
date of this prospectus.
The trust will sell the 22,875,000 common units offered hereby to the public, representing a 50% interest in the trust.
Chesapeake and the trust will enter into several agreements in connection with the conveyance of the royalty interests, including: (a) a development agreement,
which sets forth Chesapeake’s drilling obligation to the trust with respect to the Development Wells, (b) an administrative services agreement, which sets forth
Chesapeake’s obligation to provide administrative services to the trust, (c) the Drilling Support Lien and (d) a registration rights agreement, which is described under
“Trust Units Eligible For Future Sale—Registration Rights Agreement” on page 92. These first three agreements are described in more detail below.
Termination Date; Liquidation
Unless the occurrence of certain events causes the trust to dissolve at an earlier date, the trust will dissolve and begin to liquidate on the Termination Date, which
is June 30, 2031, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will automatically revert to Chesapeake, while
the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders pro rata following the Termination Date, but only after the trust has paid, or
made reasonable provision for payment of, all liabilities of the trust. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties retained by the
trust at the Termination Date. See “Description of the Royalty Interests—Sale of the Perpetual Royalties” on page 77. Any additional cash held in reserve by the trustee
will also be distributed to unitholders.
Development Agreement and Drilling Support Lien
In connection with the closing of this offering, the trust will enter into a development agreement with Chesapeake that will obligate Chesapeake to drill, or cause
to be drilled, all of the Development Wells. Chesapeake intends to drill, or cause to be drilled, the Development Wells in the AMI by June 30, 2015 and is obligated to
complete such drilling by June 30, 2016. Chesapeake will grant to the trust the Drilling Support Lien, covering Chesapeake’s retained interest in the AMI (except the
Producing Wells and any other wells that are already producing and not subject to the royalty interests) in order to secure the estimated amount of the drilling costs for
the trust’s interests in the Development Wells. The maximum amount that may be obtained by
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Index to Financial Statements
the trust pursuant to the Drilling Support Lien or through its exercise of other remedies against Chesapeake for failure to meet its drilling obligation may not exceed
$262.7 million. As Chesapeake fulfills its drilling obligation over time, Development Wells that are completed or that are perforated for completion and then plugged
and abandoned will be released from the Drilling Support Lien and the total dollar amount that may be recovered by the trust for breach of the drilling obligation will be
proportionately reduced.
Under the development agreement, a Development Well is calculated based on the perforated length of the well (measured from the first perforation along the
measured depth to the last perforation along the measured depth) and Chesapeake’s net revenue interest in such well. Chesapeake will be credited for drilling one full
Development Well if the perforated length of the well is equal to or greater than 3,500 feet and Chesapeake’s net revenue interest in the well is equal to 52.0%.
For wells with a perforated length that is less than 3,500 feet, Chesapeake will receive partial credit equal to the fraction calculated by dividing the well’s
perforated length by 3,500 feet. Chesapeake will not receive any extra credit for wells with perforated lengths in excess of 3,500 feet.
For wells in which Chesapeake has a net revenue interest greater than or less than 52.0%, Chesapeake will receive credit for such well in the proportion that its
net revenue interest in the well bears to 52.0%.
Accordingly, for example, if Chesapeake drilled one well in which it has a 80% net revenue interest, and such well were perforated to a length of 3,500 feet,
such well would count for purposes of the development agreement as 1.54 Development Wells (i.e., 3,500/3,500 x 80%/52.0%). If, on the other hand, Chesapeake
drilled one well in which it has a 50% net revenue interest, and such well were completed with a perforated length of 3,000 feet, such well would count for purposes of
the development agreement as only 0.82 Development Wells (i.e., 3,000/3,500 x 50%/52.0%).
Given that Chesapeake’s actual net revenue interest in each Development Well may be greater than or less than 52.0% and the perforated length of each well
drilled may be greater or less than 3,500 feet, Chesapeake may be required to drill more or less than 118 wells in order to fulfill its drilling obligation.
In drilling the Development Wells, Chesapeake is required to adhere to the Reasonably Prudent Operator Standard. Where Chesapeake does not operate the
Underlying Properties, Chesapeake is required to use commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying
Properties to adhere to the Reasonably Prudent Operator Standard. Chesapeake expects that the drilling and completion techniques used for the Development Wells will
be generally consistent with those used for the Producing Wells and other Colony Granite Wash producing wells outside of the AMI.
Following the drilling of each Development Well, Chesapeake is obligated to attempt to complete each such well that reasonably appears to Chesapeake, acting
in accordance with the Reasonably Prudent Operator Standard, to be capable of producing in quantities sufficient to pay drilling, completion, equipping and operating
costs. Following successful completion of such wells, Chesapeake is obligated to equip such wells for production and connect such wells to a gathering line, pipeline or
other storage or marketing facility and commence production. If Chesapeake is unable to successfully complete a Development Well, Chesapeake is obligated to plug
and abandon such well to the extent required by law.
Chesapeake will receive credit for drilling a Development Well if the well is drilled in the AMI and perforated horizontally for completion in the Colony Granite
Wash, even if such well does not successfully produce hydrocarbons. Additionally, if Chesapeake perforates a Development Well for completion and then plugs and
abandons that well, it will be released from the Drilling Support Lien.
Chesapeake may, and anticipates that it will, rely on third-party operators to fulfill a portion of its drilling, completion and equipping obligation. The trust will
not bear any of the costs of drilling, completing and equipping the Development Wells that Chesapeake drills or causes to be drilled.
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The PUD reserves reflected in the reserve reports assume that Chesapeake will drill and complete the 118 Development Wells with the same completion
technique as the 69 Producing Wells. These 69 Producing Wells produce from perforated interval lengths contributing to production ranging from less than 2,300 feet to
more than 4,600 feet. The average perforated interval length contributing to production of the 69 Producing Wells is approximately 4,100 feet, which is longer than the
3,500 foot perforated interval length upon which the definition of one full Development Well is based.
Because (a) the average perforated interval length of the wells assumed for purposes of calculating the PUD reserves is longer than the minimum perforated
interval length required for Chesapeake to receive credit for one full Development Well and (b) there is no guarantee that wells drilled with shorter perforated interval
lengths will achieve the same reserve recoveries as wells drilled with longer perforated interval lengths, you may not receive the benefit of the total amount of PUD
reserves reflected in the reserve reports, notwithstanding that Chesapeake has satisfied its drilling obligation. In addition to its obligation to adhere to the Reasonably
Prudent Operator Standard, Chesapeake’s significant retained economic interest in the trust wells through its working interest, trust unit ownership and its opportunity
to earn incentive distributions provide it with substantial incentives to pursue well completions with perforated interval lengths greater than 3,500 feet to the extent
necessary to optimize reserve recoveries for the benefit of the trust.
Chesapeake will covenant and agree not to drill or complete, and will not permit any other person within its control to drill or complete, any well in the AMI
other than a Development Well until such time as Chesapeake has met its commitment to drill the Development Wells. Once Chesapeake has completed its drilling
obligation, the trustee will be required to release the Drilling Support Lien in full. Chesapeake will further agree not to drill or complete, and will not permit any other
person within its control to drill or complete, any well that will have a perforated segment that will be within 600 feet of any perforated interval of a Development Well
or Producing Well.
Hedging Arrangements
The trust will be a party to hedging arrangements covering a portion of the trust’s oil and natural gas liquids production through September 30, 2015. As a party
to these contracts, the trust will receive payments directly from its counterparties and be required to pay any amounts owed directly to its counterparties. Any payment
due from or required to be made to such counterparties will be paid by the 40th day following the end of the calendar quarter in which such payments become due. If
one or more counterparties to the trust’s hedging arrangements were to default on its obligations to make payments under such arrangements, the cash distributions to
the trust unitholders could be materially reduced as the hedge payments are intended to provide additional cash to the trust during periods of lower oil and natural gas
liquids prices.
Chesapeake will have authority, in its role as hedge manager to the trust, to terminate, restructure or otherwise modify all or any portion of the trust’s hedging
arrangements to the extent that Chesapeake reasonably determines, acting in good faith, that the oil and natural gas liquids volumes hedged under such portion of the
contracts exceed, or are expected to exceed, the combined estimated oil and natural gas liquids production attributable to the trust’s royalty interests over the periods
hedged. The counterparties may require Chesapeake to terminate, restructure or otherwise modify the hedging arrangements if Chesapeake does not drill a specified
number of Development Wells in each six-month period ending June 30 or December 31 during the term of the hedging arrangements and the counterparties determine
that the oil and natural gas liquids volumes hedged under such portion of the contracts exceed, or are expected to exceed, the combined estimated oil and natural gas
liquids production attributable to the trust’s royalty interests over the periods hedged. Except in such limited circumstances, the trust will not have the ability to enter
into additional hedges and, accordingly, after the expiration of the hedging arrangements at the end of the third quarter of 2015, no production will be hedged. For more
information on Chesapeake’s role as hedge manager for the trust, please see “—Administrative Services Agreement” on page 49.
Under the hedging arrangements and separate from the drilling obligation under the development agreement, Chesapeake will be required to drill and complete,
or cause to be drilled and completed, a specified
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number of Development Wells by the end of each six-month period ending June 30 and December 31 during the term of the hedging arrangements. In addition, with
respect to each such six-month period, the trust will be required to deliver to the counterparties and the collateral agent under the hedging arrangements (a) an
independent reserve engineers’ report that sets forth the total reserves estimated to be attributable to the trust’s interest in the Underlying Properties as of the end of such
period and such other information as is typically included in, or required under SEC rules to be included in, summary reserve engineers reports and (b) a report that sets
forth certain information regarding the Development Wells drilled and completed as of the end of such six-month period.
The trust’s and Chesapeake’s obligations to the counterparties under the hedging arrangements will be secured by the trust’s royalty interests in the Underlying
Properties. Subject to any applicable notice and cure periods, if, among other things, the trust or Chesapeake is in material default of the drilling, payment or reporting
obligations under the hedging arrangements or becomes subject to bankruptcy proceedings or the trust becomes subject to certain change of control transactions, the
hedging counterparties may foreclose on the lien on the trust’s royalty interests in the Underlying Properties. In addition, the trust’s hedging arrangements will contain a
prohibition on the trust granting additional liens on any of its properties, other than customary permitted liens and liens in favor of the trustees of the trust. Under the
trust agreement, the trustee may create a cash reserve to pay for future expenses of the trust.
Under the hedging arrangements, the trust will hedge approximately 50% of the expected oil and natural gas liquid production and 38% of the expected revenues
(based on NYMEX strip oil prices as of October 14, 2011) upon which the target distributions from October 1, 2011 through September 30, 2015 are based. Estimated
production of natural gas liquids will be hedged with oil contracts using a conversion ratio of one barrel of natural gas liquids to 49.2% of a barrel of oil. The remaining
estimated production of oil and natural gas liquids during that time, all production of natural gas during that time and all production after such time will not be hedged,
except in connection with the restructuring of an existing hedge. The trust’s hedging arrangements will not be qualified for hedge accounting treatment, and therefore all
future mark-to-market fluctuations will be recorded to the statement of operations.
The following tables illustrate the application of oil swaps between oil and natural gas liquids production, notional amount and weighted average fixed price for
the hedging arrangements into which the trust will enter.
Volume
(mbbl)
Weighted Average Price
(per bbl)
Oil:
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
Q1 2013
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Q4 2014
Q1 2015
Q2 2015
Q3 2015
Total Oil
48
89.7
89.2
91.4
97.2
102.3
99.4
101.1
104.1
101.6
97.7
96.3
97.1
95.0
92.5
95.3
80.6
$ 84.37
84.99
85.71
86.40
86.98
87.37
87.60
87.79
87.99
88.08
88.21
88.34
88.45
88.59
88.76
88.90
1530.5
$ 87.42
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Index to Financial Statements
Volume
(mbbl)
Natural Gas Liquids:
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
Q1 2013
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Q4 2014
Q1 2015
Q2 2015
Q3 2015
Total Natural Gas Liquids
Weighted Average Price
(per bbl)
150.1
151.4
153.4
161.5
169.1
168.3
169.0
170.5
167.8
167.1
170.8
166.0
161.1
159.7
162.9
148.5
$ 41.50
41.80
42.16
42.50
42.79
42.98
43.09
43.18
43.28
43.33
43.39
43.46
43.51
43.58
43.66
43.73
2597.2
$ 43.01
Administrative Services Agreement
In connection with the closing of this offering, the trust will enter into an administrative services agreement with Chesapeake pursuant to which Chesapeake will
provide the trust with certain accounting, tax preparation, bookkeeping and informational services related to the royalty interests and the registration rights agreement.
Additionally, the administrative services agreement will designate Chesapeake as the trust’s hedge manager, pursuant to which Chesapeake will have authority,
on behalf of the trust, to administer the trust’s hedging arrangements. As hedge manager, Chesapeake will have authority to terminate, restructure or otherwise modify
all or any portion of the trust’s hedging arrangements to the extent that Chesapeake reasonably determines, acting in good faith, that the oil and natural gas liquids
volumes hedged (taken together, using a per barrel conversion ratio of natural gas liquids to oil of 49.2%) under such portion of the contracts exceed, or are expected to
exceed, the combined estimated oil and natural gas liquids production attributable to the trust’s royalty interests over the periods hedged. However, in fulfilling its role
as hedge manager, Chesapeake will not act as a fiduciary for the trust and will have no affirmative duty to modify any of the trust’s hedges, except as required by the
hedging arrangements. Moreover, under the trust agreement, Chesapeake will be indemnified by the trust for any actions it takes in this regard.
In return for the services provided by Chesapeake to the trust under the administrative services agreement, the trust will pay Chesapeake, on a quarterly basis, a
total annual fee of $200,000. Chesapeake will also be entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with
the provision of any of the services under the agreement.
The administrative services agreement will terminate upon the earliest to occur of: (a) the date the trust shall have been wound up in accordance with the trust
agreement, (b) the date that all of the royalty interests have been terminated or are no longer held by the trust, (c) with respect to services to be provided with respect to
any Underlying Properties being transferred by Chesapeake, the date that either Chesapeake or the trustee may designate by delivering 90-days prior written notice,
provided that Chesapeake’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in
place of Chesapeake, or (d) a date mutually agreed by Chesapeake and the trustee.
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TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
Chesapeake will convey to the trust royalty interests in specified oil, natural gas liquids and natural gas properties in the AMI. The PDP Royalty Interest will
entitle the trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production expenses and any applicable
taxes) from the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake’s net revenue interest in the Producing Wells. The Development
Royalty Interest will entitle the trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production expenses and
any applicable taxes) from the sale of future production of oil, natural gas liquids and natural gas attributable to Chesapeake’s net revenue interest in the Development
Wells.
The amount of trust revenues and cash distributions to trust unitholders will depend on:
•
the timing of initial production from the Development Wells;
•
oil, natural gas liquids and natural gas prices received;
•
the volume of oil, natural gas liquids and natural gas produced and sold;
•
amounts realized and paid under hedging arrangements;
•
post-production expenses and any applicable taxes; and
•
the trust’s expenses.
Chesapeake has established quarterly target levels of cash distributions for the life of the trust. Such target distribution levels are set forth on Annex B to this
prospectus. The target distributions were prepared by Chesapeake on a cash basis based on assumptions regarding production volumes, pricing and other assumptions
that are described below in “—Significant Assumptions Used to Calculate the Target Distributions” beginning on page 56. The production forecasts are estimates
prepared by Ryder Scott and have been used to calculate target distributions. Actual cash distributions to the trust unitholders will fluctuate quarterly based on quantity
of oil, natural gas liquids and natural gas produced from the Underlying Properties, the prices received for such production, payments under the hedge arrangements, the
trust’s administrative expenses and other factors. Chesapeake will pay to the trust each quarter an amount equal to the trust’s royalty interest in the proceeds of
production from the Underlying Properties received during the calendar quarter most recently ended (after deducting post-production expenses and any applicable
taxes). The trust, in turn, will make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the trust’s expenses, to holders of trust
units approximately 60 days following the end of each quarter through and including the quarter ending June 30, 2031.
The first distribution, which will cover the third quarter of 2011, is expected to be made on or about December 1, 2011 to record unitholders on or about
November 21, 2011. The trustee intends to withhold $1.0 million from the first distribution to establish an initial cash reserve available for trust expenses. If the trustee
uses such cash reserve to pay for trust expenses, the reserve must be replenished before any further quarterly distributions are made to trust unitholders. Additional cash
reserves may also be established from time to time as determined by the trustee to pay future expenses of the trust. Due to the timing of the payment of production
proceeds to the trust, the trust expects that the first distribution will include royalties attributable to sales for oil, natural gas liquids and natural gas for two months (July
and August 2011). Thereafter, quarterly distributions will generally include royalties attributable to sales of oil, natural gas liquids and natural gas for three months,
including the first two months of the quarter just ended and the last month of the quarter prior to that one. Because payments to the trust will be generated by depleting
assets and production from the Underlying Properties will diminish over time, a portion of each distribution will represent a return of your original investment.
In order to provide support for cash distributions on the common units, Chesapeake has agreed to subordinate 11,437,500 of the trust units it will retain
following this offering, which will constitute 25% of the
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Index to Financial Statements
outstanding trust units. The subordinated units will be entitled to receive pro rata distributions from the trust if and to the extent there is sufficient cash to provide a cash
distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is insufficient cash to fund such a distribution on all trust
units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the
subordination threshold amount on the common units. Each applicable quarterly subordination threshold is 20% below the target distribution level for the corresponding
quarter, as reflected on Annex B. In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to Chesapeake to
perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, Chesapeake will be entitled to receive incentive
distributions equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter during the subordination period exceeds the
target distribution for such quarter by more than 20%. Chesapeake’s right to receive incentive distributions will terminate upon the expiration of the subordination
period.
The subordinated units will automatically convert into common units on a one-for-one basis and Chesapeake’s right to receive incentive distributions will
terminate at the end of the fourth full calendar quarter following Chesapeake’s satisfaction of its drilling obligation to the trust. Chesapeake currently intends to
complete its drilling obligation on or before June 30, 2015 and accordingly, Chesapeake expects the subordinated units will convert into common units on or before
June 30, 2016. Chesapeake is obligated to complete its drilling obligation by June 30, 2016, in which event the subordinated units would convert into common units on
or before June 30, 2017.
Chesapeake’s management has prepared the prospective financial information set forth below to present the target cash distributions to the holders of
the trust units based on the estimates and assumptions described below. The accompanying prospective financial information was not prepared with a view
toward complying with the regulations of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to
preparation and presentation of prospective financial information. More specifically, such information omits items that are not relevant to the trust, such as
changes in financial position, an earnings per unit measure and certain non-cash expenses for depreciation, depletion and amortization used to arrive at a
GAAP net income measure. Chesapeake’s management believes the prospective financial information was prepared on a reasonable basis, reflects the best
currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and the expected
future financial performance of the royalty interests. However, this information is based on estimates and judgments, and readers of this prospectus are
cautioned not to place undue reliance on the prospective production or financial information.
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, Chesapeake’s management.
PricewaterhouseCoopers LLP, the trust’s and Chesapeake’s independent registered public accountant, has neither examined, compiled nor performed any
procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion
or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included or incorporated by reference in this prospectus
relate to the historical Statement of Assets and Trust Corpus of the trust, the historical Statements of Revenues and Direct Operating Expenses of the
Underlying Properties and the historical financial statements of Chesapeake. The reports do not extend to the prospective financial information and should
not be read to do so.
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The following table sets forth the target distributions and subordination and incentive thresholds for each calendar quarter through the second quarter of 2017.
The effective date of the conveyance of the royalty interests is July 1, 2011, which means that the trust will receive credit for the proceeds of production attributable to
the royalty interests from that date even though the trust properties will not be conveyed to the trust until the closing of this offering.
Period
Subordination
Threshold (1)
Target
Distribution
(per unit)
2011:
Third Quarter(2)
Fourth Quarter
$
$
0.37
0.56
0.46
0.70
Incentive
Threshold (1)
$
0.55
0.85
2012:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.59
0.61
0.63
0.68
0.74
0.76
0.79
0.85
0.89
0.91
0.95
1.02
2013:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.70
0.70
0.72
0.70
0.87
0.87
0.90
0.88
1.05
1.05
1.08
1.05
2014:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.70
0.69
0.70
0.67
0.88
0.86
0.87
0.84
1.06
1.04
1.05
1.00
2015:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.67
0.69
0.65
0.56
0.84
0.86
0.81
0.70
1.00
1.03
0.97
0.84
2016:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
0.51
0.47
0.44
0.42
0.64
0.59
0.55
0.52
0.77
0.71
0.66
0.62
2017:
First Quarter
Second Quarter
0.39
0.38
0.49
0.47
0.59
0.56
(1)
(2)
The subordination and incentive thresholds terminate after the fourth full calendar quarter following Chesapeake’s completion of its drilling obligation.
Includes proceeds attributable to two months of actual production from July and August 2011, and gives effect to the establishment of a $1.0 million reserve for trust expenses
withheld by the trustee.
Chesapeake has prepared the operational and financial information set forth above and below in order to present the target distributions attributable to the oil,
natural gas liquids and natural gas sales volumes reflected in the reserve reports included as Annex A to this prospectus. The target distributions, in the view of
Chesapeake’s management, were prepared on a reasonable basis based on the assumptions outlined in “—Significant Assumptions Used to Calculate the Target
Distributions” beginning on page 56.
52
Table of Contents
Index to Financial Statements
The operational and financial targets outlined below should not be relied upon as being necessarily indicative of actual future results. Neither Chesapeake nor the
trust undertakes any obligation to update the financial forecast to reflect events or circumstances after the date of this prospectus and readers of this prospectus are
cautioned not to place undue reliance on this financial information.
The projections and assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Chesapeake and the
trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon the occurrence of events or conditions that are different
from the events or conditions assumed to occur for purposes of these operational and financial targets.
Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil, natural gas liquids and natural gas prices and production volumes. See
“—Sensitivity of Target Distributions to Changes in Oil, Natural Gas Liquids and Natural Gas Prices and Volumes” beginning on page 61, which shows estimated
effects to cash distributions through June 30, 2012 from changes in assumed realized oil, natural gas liquids and natural gas prices as well as changes in estimated
production volumes. As a result of typical production declines for oil, natural gas liquids and natural gas properties, production estimates generally decrease from year
to year. However, the production estimates included in the table below reflect that these declines are expected to be offset by additional production from Development
Wells as they are completed and begin to produce. The timing of the completion of, and the amount of production attributable to, the Development Wells are
substantially dependent on Chesapeake executing its drilling plans with respect to the drilling and completion of the Development Wells in a manner substantially
similar to those underlying the assumptions used in establishing these target distributions. In addition, the completion of Chesapeake’s drilling obligation will depend,
in part, on the completion of drilling for certain Development Wells by third parties, over whom Chesapeake has no control, in a manner consistent with the
assumptions used in establishing these target distributions. Please see “Risk Factors” beginning on page 20 for risks relating to the timing of drilling and amount of
production attributable to the Development Wells. As a result of these factors, the target distributions shown in the tables below are not necessarily indicative of
the actual distributions for future years.
Because payments to the trust will be generated by depleting assets and production from the Underlying Properties will diminish over time, a portion of each
distribution will represent a return of your original investment. See “Risk Factors—The oil, natural gas liquids and natural gas reserves estimated to be attributable to
the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil
and gas properties or royalty interests to replace the depleting assets and production” on page 27.
53
Table of Contents
Index to Financial Statements
The table below presents the calculation of the target distributions for each quarter through and including the quarter ending June 30, 2012.
Three Months Ending
September 30,
2011 (1)
Period
Estimated production from trust properties
Oil sales volumes (mbbls)
Natural gas liquids sales volumes (mbbls)
Natural gas sales volumes (mmcf)
Total sales volumes (mboe)
% PDP sales volumes
% PUD sales volumes
% Oil volumes
% Natural gas liquids volumes
% Natural gas volumes
Commodity price and derivative contract positions
NYMEX futures price(2)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Natural gas ($/mmbtu)
Assumed realized weighted unhedged price(3)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Natural gas ($/mcf)
Assumed realized weighted hedged price(4)
Oil ($/bbl)
Natural gas liquids ($/bbl)
Percent of oil volumes hedged
Oil hedged price ($/bbl)
Percent of natural gas liquids volumes hedged
Natural gas liquids hedged price ($/bbl)
Estimated cash available for distribution
Oil sales revenues
Natural gas liquids sales revenues
Natural gas sales revenues
Realized gains (losses) from derivative contracts
December 31
,
March 31,
2011 (1)
2012 (1)
(In thousands, except volumetric and per unit data)
June 30,
2012 (1)
103
179
1,720
178
299
2,876
181
302
2,909
181
304
2,923
569
956
967
972
100%
–
84%
16%
69%
31%
61%
39%
18%
32%
50%
19%
31%
50%
19%
31%
50%
19%
31%
50%
$
$
$
95.93
47.15
4.36
$
$
$
86.03
42.31
3.78
$
$
$
87.10
42.85
4.06
$
$
$
87.35
42.97
4.07
$
$
$
92.35
44.76
3.12
$
$
$
82.45
40.01
2.48
$
$
$
83.52
40.46
2.81
$
$
$
83.77
40.45
2.98
$
$
92.35
44.76
–
–
–
–
$
$
81.56
39.57
33.1%
84.18
33.6%
41.41
$
$
82.34
39.88
49.9%
84.74
50.0%
41.68
$
$
82.83
39.99
50.0%
85.48
50.0%
42.05
9,554
8,030
5,358
–
$
$
$
$
Operating revenues and realized gains (losses) from derivative
contracts
Production taxes
Trust administrative expenses(5)
Total trust expenses
$
$
14,648
11,953
7,120
(289)
$
$
$
$
$
15,083
12,220
8,172
(389)
$ 15,175
12,278
8,707
(309)
22,942
(726)
(1,327)
33,432
(935)
(250)
35,085
(938)
(250)
35,851
(930)
(250)
(2,053)
(1,185)
(1,188)
(1,180)
Cash available for distribution
$
20,890
$
32,247
$
33,896
$ 34,670
Trust units outstanding
Target distribution per trust unit
$
45,750
0.46
$
45,750
0.70
$
45,750
0.74
$
45,750
0.76
Subordination threshold per trust unit
$
0.37
$
0.56
$
0.59
$
0.61
Incentive threshold per trust unit
$
0.55
$
0.85
$
0.89
$
0.91
54
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Index to Financial Statements
Three Months Ending
September 30,
2011 (1)
Period
If actual cash exceeds targeted by 20%
Cash necessary to meet incentive threshold
$
Excess cash available for incentive distributions
Distributions to unitholders
Incentive distributions to Chesapeake
If actual cash available exceeds targeted by 40%
Cash necessary to meet incentive threshold
$
Excess cash available for incentive distributions
Distributions to unitholders
Incentive distributions to Chesapeake
If actual cash available falls short of projected by 20%
Cash available for distribution to common units
Cash necessary to meet common unit subordination threshold
Cash short of subordination threshold
Reduction in distribution to subordinated units to support subordination
threshold
Cash distributions to common unitholders
Cash distributions to subordinated units
$
If actual cash available falls short of projected by 40%
Cash available for distribution to common units
Cash necessary to meet common unit subordination threshold
Cash short of subordination threshold
Reduction in distribution to subordinated units to support subordination
threshold
Cash distributions to common unitholders
$
25,068
25,068
—
—
—
29,246
25,068
$
$
38,696
38,696
—
—
—
45,146
38,696
$
$
40,676
40,676
—
—
—
47,455
40,676
June 30,
2012 (1)
$
$
41,604
41,604
—
—
—
48,539
41,604
4,178
2,089
6,449
3,225
6,779
3,390
6,934
3,467
2,089
3,225
3,390
3,467
16,712
12,534
12,534
25,798
19,348
19,348
27,117
20,338
20,338
27,736
20,802
20,802
—
—
—
—
—
12,534
—
19,348
—
20,338
—
20,802
4,178
$
6,449
$
6,779
$
6,934
12,534
9,400
12,534
19,348
14,511
19,348
20,338
15,253
20,338
20,802
15,602
20,802
(3,133)
(4,837)
(5,084)
(5,201)
3,133
12,534
—
Cash distributions to subordinated units
December 31,
March 31,
2011 (1)
2012 (1)
(In thousands, except volumetric and per unit data)
$
4,837
19,348
—
$
5,084
20,338
—
$
5,201
20,802
—
(1)
The three months ending September 30, 2011 include proceeds attributable to the first two months of production from July 1, 2011 to August 31, 2011. Thereafter, quarterly
distributions will generally include royalties attributable to sales of oil, natural gas liquids and natural gas for three months, including the first two months of the quarter just ended
and the last month of the quarter prior to that one.
(2)
Average NYMEX settled and futures prices, as reported October 14, 2011. For a description of the effect of lower NYMEX prices on target cash distributions, see “—Sensitivity of
Target Distributions to Changes in Oil, Natural Gas Liquids and Natural Gas Prices and Volumes” beginning on page 61.
Sales price net of forecasted gravity, quality, btu content, transportation costs, and marketing costs. For information about the estimates and assumptions made in preparing the table
above, see “—Significant Assumptions Used to Calculate the Target Distributions” beginning on page 56.
No hedging arrangements will cover natural gas.
Includes the establishment of an initial cash reserve of $1.0 million for trust expenses in period ending September 30, 2011.
(3)
(4)
(5)
55
Table of Contents
Index to Financial Statements
Unaudited Pro Forma Distributable Income
If the conveyance of the royalty interests and the closing of this offering had taken place on January 1, 2010, pro forma distributable income of the trust for the
year ended December 31, 2010 would have been $153.0 million or $3.34 per trust unit. This amount would have been sufficient to pay the aggregate target distributions
for the four quarters ending September 30, 2012 of $2.99 per trust unit. If the conveyance of the royalty interests and the closing of this offering had taken place on
January 1, 2011, pro forma distributable income of the trust for the six months ended June 30, 2011 would have been $72.8 million or $1.59 per trust unit. This amount
would have been sufficient to pay the aggregate target distributions for the two quarters ending March 31, 2012 of $1.44 per trust unit. For a calculation of the pro
forma distributable income of the trust for these periods, please read “Chesapeake Granite Wash Trust—Unaudited Pro Forma Statement of Distributable Income” on
page F-16.
Significant Assumptions Used to Calculate the Target Distributions
In preparing the target distributions and subordination and incentive threshold tables above and sensitivity tables below, the revenues and expenses of the trust
were calculated based on the terms of the conveyances creating the trust’s royalty interests using the following assumptions and those set forth above under “Target
Distributions and Subordination and Incentive Thresholds” beginning on page 50. These estimations are described under “Description of the Royalty Interests”
beginning on page 78.
Production Estimates. As more fully described in the reserve report, our forecasts of future production rates are based on historical performance data for the
Producing Wells, and test data and other related information was used to estimate the anticipated initial production rates for the Development Wells. The estimates of
reserves and production relating to the Underlying Properties and the royalty interests included in the reserve reports have been made in accordance with the SEC’s
rules for reserve reporting, including historical pricing. The estimated production in the forecast period gives effect to Chesapeake’s drilling schedule of approximately
30 wells each year.
Oil Prices. The assumed unhedged oil prices utilized for purposes of preparing the target distributions are based on settled NYMEX pricing for July through
October 2011, NYMEX forward pricing for the remainder of the period ending June 30, 2014 and assumed price increases after June 30, 2014 of 2.5% annually, capped
at $120.00 per bbl of oil. Using these assumptions, the price per bbl of oil would reach the $120.00 cap in 2026. These prices are higher than the SEC-mandated pricing
used in the reserve reports of $89.86 per bbl of oil. The table below sets forth NYMEX pricing as of October 14, 2011 for period ending June 30, 2014.
Assumed Market Prices for Oil ($/bbl)
Based on NYMEX Pricing
as of October 14, 2011
2011
January
February
March
April
May
June
July
August
September
October
November
December
$
(1)
Based on settled NYMEX pricing.
56
–
–
–
–
–
–
93.40(1)
98.14(1)
84.12(1)
86.89(1)
86.80
87.00
2012
2013
$ 87.10
87.22
87.31
87.35
87.39
87.43
87.53
87.63
87.79
87.98
88.24
88.51
$ 88.58
88.61
88.64
88.65
88.66
88.68
88.68
88.69
88.71
88.80
88.91
89.02
2014
$
89.01
89.01
89.02
89.04
89.08
89.12
–
–
–
–
–
–
Table of Contents
Index to Financial Statements
Natural Gas Liquids Prices. The assumed unhedged natural gas liquids prices utilized for purposes of preparing the target distributions are benchmarked at
49.2% of the oil prices set forth above under the heading “—Oil Prices” on page 56 as well as a 1.9% to 3.0% negative differential from such prices in each relevant
period. See “—Differentials” on page 59.
Natural Gas Prices. The assumed natural gas prices utilized for purposes of preparing the target distributions are based on settled NYMEX pricing for July
through October 2011, NYMEX forward pricing for the remainder of the period ending June 30, 2014 and assumed price increases after June 30, 2014 of 2.5%
annually, capped at $7.00 per mmbtu. Using these assumptions, the price per mmbtu would reach the $7.00 cap in 2028. These prices are higher than the SEC-mandated
pricing used in the reserve reports of $4.21 per mcf of natural gas. The table below sets forth NYMEX pricing as of October 14, 2011 for the period ending June 30,
2014.
Assumed Market Prices for Natural Gas ($/mmbtu)
Based on NYMEX Pricing
as of October 14, 2011
2011
January
February
March
April
May
June
July
August
September
October
November
December
$
(1)
–
–
–
–
–
–
4.36(1)
4.37(1)
3.86(1)
3.76(1)
3.70
3.96
2012
2013
$ 4.10
4.11
4.07
4.05
4.09
4.13
4.17
4.19
4.20
4.23
4.38
4.65
$ 4.79
4.76
4.70
4.57
4.59
4.62
4.66
4.68
4.68
4.71
4.83
5.06
2014
$
5.18
5.14
5.06
4.85
4.86
4.89
–
–
–
–
–
–
Based on settled NYMEX pricing.
Hedging. The trust will be a party to hedging arrangements pursuant to which the trust will hedge approximately 50% of the expected oil and natural gas liquids
production and 37% of the trust’s expected revenues upon which the target distributions from October 1, 2011 to September 30, 2015 are based. Except in connection
with the restructuring of an existing hedge, after such date, no production will be hedged. See “The Trust—Hedging Arrangements” beginning on page 47.
57
Table of Contents
Index to Financial Statements
The following tables illustrate the application of oil swaps between oil and natural gas liquids production, notional amount and weighted average fixed price for
the hedging arrangements into which the trust will enter.
Volume
(mbbl)
Weighted Average Price
(per bbl)
Oil:
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
Q1 2013
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Q4 2014
Q1 2015
Q2 2015
Q3 2015
Total Oil
89.7
89.2
91.4
97.2
102.3
99.4
101.1
104.1
101.6
97.7
96.3
97.1
95.0
92.5
95.3
80.6
$ 84.37
84.99
85.71
86.40
86.98
87.37
87.60
87.79
87.99
88.08
88.21
88.34
88.45
88.59
88.76
88.90
1530.5
$ 87.42
Volume
(mbbl)
Natural Gas Liquids:
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
Q1 2013
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Q4 2014
Q1 2015
Q2 2015
Q3 2015
Total Natural Gas Liquids
58
Weighted Average Price
(per bbl)
150.1
151.4
153.4
161.5
169.1
168.3
169.0
170.5
167.8
167.1
170.8
166.0
161.1
159.7
162.9
148.5
$ 41.50
41.80
42.16
42.50
42.79
42.98
43.09
43.18
43.28
43.33
43.39
43.46
43.51
43.58
43.66
43.73
2597.2
$ 43.01
Table of Contents
Index to Financial Statements
Differentials. Proceeds to the trust will be calculated based on the actual price realized by Chesapeake for oil, natural gas liquids and natural gas produced, which
will differ from NYMEX prices as a result of:
•
discounts based on location;
•
quality of oil, natural gas liquids and natural gas produced;
•
estimated fuel usage for natural gas; and
•
post-production expenses other than production taxes (generally consisting of costs incurred to gather, store, compress, transport, process,
treat, dehydrate and market the oil, natural gas liquids and natural gas produced).
These charges are collectively referred to as pricing “differentials” from NYMEX pricing.
To prepare the target distributions, assumed differentials were subtracted from the NYMEX prices shown in the tables above, based on an analysis by
Chesapeake of historical realized prices for production from the region.
The estimated realized prices for oil assume a $3.58 per barrel negative differential from the NYMEX futures price for oil to reflect recent field adjustments and
post-production expenses. A flat dollar differential amount has been utilized because the realized oil differential has historically been stable for oil produced in the
Colony Granite Wash.
The estimated realized prices for natural gas assume a negative differential which varies based on assumed NYMEX prices. For purposes of calculating the
target distributions, the estimated differential is $1.23 per mcf in July 2011 and escalates to $1.95 per mcf in 2029, remaining flat thereafter.
The estimated realized prices for natural gas liquids are benchmarked at 49.2% of NYMEX settled and futures prices for oil based on an analysis by Chesapeake
of the historical mix of hydrocarbon liquids that have been produced from its wells in the region. Additionally, the estimated prices assume a 1.9% to 3.0% negative
differential from NYMEX settled and futures prices for oil associated with fees paid for gathering and processing of the natural gas liquids, consistent with
Chesapeake’s service contracts currently in place.
There can be no assurance that realized prices in the future will be the same as historical realized prices or the assumed realized prices used to prepare the target
distributions.
Administrative Expense. Trust administrative expenses per year are estimated to be approximately $1.0 million, although such costs could be greater or less
depending on future events that cannot be predicted. Included in the annual estimate, among other miscellaneous items, is an annual administrative fee of $175,000 for
the trustee, which may be adjusted beginning on January 1, 2015 as provided in the trust agreement, an annual administrative fee of $2,000 for the Delaware trustee and
an annual fee of $200,000 payable to Chesapeake pursuant to the terms of the administrative services agreement. It has been assumed that the annual fee to Chesapeake
will remain flat for the 20-year life of the trust, while the fees to the trustee and the Delaware trustee will escalate at a rate of approximately 2.5% annually starting in
the first quarter of 2015. It has been assumed that the trust will also pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal
expenses incurred in forming the trust as well as the trustee’s acceptance fee in the amount of $10,000. These costs will be deducted by the trust before distributions are
made to trust unitholders.
Trustee’s Cash Reserve. It has been assumed that the trustee will withhold $1.0 million from the first distribution to establish an initial cash reserve available for
expenses of the trust. No other cash reserves have been assumed.
Tax Treatment of Royalty Interests. For U.S. federal income tax purposes, the Term PDP Royalty and the Term Development Royalty should be treated as debt
instruments. Accordingly, the Term Royalties will be subject to the original issue discount, or OID, rules of the Internal Revenue Code, which require that payments
59
Table of Contents
Index to Financial Statements
made to the trust with respect to the Term Royalties will be treated first as consisting of a payment of interest to the extent of interest deemed accrued under the OID
rules at the applicable federal rate and the excess, if any, will be treated as a payment of principal (which is non-taxable). For federal income tax purposes, the Perpetual
PDP Royalties will be, and the Perpetual Development Royalties should be, treated as mineral royalty interests, which give rise to ordinary income subject to depletion.
Timing of Actual Cash Distributions. Quarterly cash distributions will be made approximately 60 days following the end of each calendar quarter to unitholders
of record approximately 50 days following each calendar quarter. Due to the timing of Chesapeake’s receipt of cash for production, it has been assumed that cash
distributions for each quarter will include three months of production, including the first two months of the quarter just ended and the last month of the quarter prior to
that one. The first distribution, which will cover the third quarter of 2011, is expected to be made on or about December 1, 2012 to record unitholders on or about
November 21, 2011, and will generally include sales of oil, natural gas liquids and natural gas for the months of July and August 2011.
Applicable Taxes. Oklahoma imposes a tax on the production of oil and natural gas in the state at the statutory tax rate of approximately 7%. Current Oklahoma
law provides for a reduced rate of approximately 1% for the first four years of production from horizontal wells so long as the well is producing before July 1, 2015.
Prior to July 1, 2011, Oklahoma law provided for a reduced rate of approximately 1% for the first four years of production from horizontal wells; however, this reduced
rate was limited to the earlier of (i) four years or (ii) when the well reached payout as defined under Oklahoma law. Thereafter, the Producing Wells would revert to the
statutory tax rate or, if applicable, another reduced rate. Currently, some of the Producing Wells have reached payout and are subject to a tax rate in excess of 1%.
Accordingly, the effective rate of production tax on the oil and gas attributable to the properties owned by the trust will be approximately 2% for the first four years of
production. After the four year exemption period, the statutory rate of approximately 7% will apply to the properties.
Incentive Distributions. To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period,
Chesapeake will be entitled to receive 50% of such cash as incentive distributions. The incentive distributions terminate upon completion of the subordination period.
Valuation of Perpetual Royalties. In estimating the cash available for distribution to trust unitholders following the Termination Date, we valued the royalty
interests attributable to the Perpetual Royalties, which the trust will own on the Termination Date and subsequently sell, at $98.4 million as of the Termination Date. We
determined this value using a discounted cash flow analysis as follows:
•
a discount rate of 9%;
•
estimated future production of 5.0 mmboe following the Termination Date, which is based on reserve and production data from the reserve reports
attributable to the Perpetual Royalties; and
•
assumed prices of $120.00 per bbl of oil as set forth above under the heading “—Oil Prices” on page 56, $59.03 per bbl of natural gas liquids as set
forth above under the heading “—Natural Gas Liquids Prices” on page 57 and $7.00 per mmbtu of natural gas as set forth above under the heading
“—Natural Gas Prices” on page 57, each as adjusted as set forth above under the heading “—Differentials” on page 59.
The actual value of the Perpetual Royalties sold by the trust following the Termination Date and the proceeds available for distribution to trust unitholders from
such sale will depend on numerous factors out of Chesapeake’s or the trust’s control, including the estimated future production of the reserves attributable to the
Perpetual Royalties on the Termination Date, current and expected commodity prices as of the Termination Date and the discount rate employed by prospective
purchasers. For example, a discount rate of 6% would increase the estimated value noted above by $21.0 million. Conversely, a discount rate of 12% would decrease
the estimated value noted above by $14.5 million.
60
Table of Contents
Index to Financial Statements
Sensitivity of Target Distributions to Changes in Oil, Natural Gas Liquids and Natural Gas Prices and Volumes
The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales prices for oil, natural gas liquids and
natural gas sold, the volumes of oil, natural gas liquids and natural gas produced and, to some degree, variations in property and production taxes, if any, and
post-production expenses. The following tables demonstrate the effect that changes in the estimated oil, natural gas liquids and natural gas production for the forecast
period ending June 30, 2012 as reflected in the reserve reports and the impact that fluctuations in assumed realized oil, natural gas liquids and natural gas prices could
have on cash distributions to the trust unitholders.
These tables set forth the sensitivity of annual cash distributions per trust unit for the forecast period ending June 30, 2012 based upon:
•
the assumption that a total of 34,312,500 common trust units and 11,437,500 subordinated units are issued and outstanding after the closing of the
offering made hereby;
•
an assumed initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover page of this prospectus);
•
various realizations of oil, natural gas liquids and natural gas production levels estimated in the reserve reports;
•
various assumed realized oil, natural gas liquids and natural gas prices;
•
assumptions regarding applicable taxes and differentials; and
•
other assumptions described above under “—Significant Assumptions Used to Calculate the Target Distributions” beginning on page 56.
The tables give effect to the subordination and incentive distribution features that are contained in the terms of the trust. For a description of the way in which
those features would impact trust unitholders’ distributions, please see “Target Distributions and Subordination and Incentive Thresholds” beginning on page 50. The
assumed realized prices of oil, natural gas liquids and natural gas production shown have been chosen solely for illustrative purposes, and do not reflect any hedging
assumptions.
The following tables are not a projection or forecast of the actual or estimated results from an investment in the common units. The purpose of these
tables is to illustrate the sensitivity of cash distributions to changes in oil, natural gas liquids and natural gas production levels and the price of oil, natural gas
liquids and natural gas. There is no assurance that the assumptions described below will actually occur or that oil, natural gas liquids and natural gas
production levels and the prices of oil, natural gas liquids and natural gas will not change by amounts different from those shown in the tables.
The hedging arrangements for the trust will be in effect only through September 30, 2015, and thus there is likely to be greater fluctuation in cash
distributions resulting from fluctuations in realized oil and natural gas liquids prices in periods subsequent to the end of the term of the hedging
arrangements. See “Risk Factors” beginning on page 20 for a discussion of various items that could impact production levels and the prices of oil, natural gas
liquids and natural gas.
These distributions are sensitized to both assumed NYMEX oil and natural gas prices as well as the assumed production from the trust properties. The quarterly
distributions in the tables below are based on assumptions outlined in “—Significant Assumptions Used to Calculate the Target Distributions” beginning on page 56.
The tables set forth below provide examples of possible distributions for the quarters ending September 30, 2011, December 31, 2011, March 31, 2012 and June 30,
2012 based on various NYMEX pricing and production assumptions.
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Index to Financial Statements
For scenarios in these tables that involve lower NYMEX oil or natural gas prices and production volumes, as applicable, the quarterly distribution per unit does
not fall below the subordination threshold because the subordinated units support the common distributions.
The distributions below reflect average NYMEX futures prices as reported on October 14, 2011. The estimated oil and natural gas production used to calculate
the distributions below is based on the reserve reports, and the sensitivity analysis assumes there will be no variation by location and that oil, natural gas liquids and
natural gas production will continue to represent the same relative percentage of total production as estimated in the reserve reports.
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Index to Financial Statements
(1)
Includes proceeds attributable to two months of production in July and August of 2011.
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THE UNDERLYING PROPERTIES
The Underlying Properties consist of the working interests owned by Chesapeake in the Colony Granite Wash in Washita County in western Oklahoma arising
under leases and farmout agreements related to properties from which the PDP Royalty Interest and the Development Royalty Interest will be conveyed. The AMI
consists of approximately 45,400 gross acres (28,700 net acres). There are more than 200 potential drilling locations within the AMI based on assumed spacing of four
wells per 640-acre section. As of June 30, 2011 and after giving effect to the conveyance of the PDP Royalty Interest and the Development Royalty Interest to the trust,
the total reserves estimated to be attributable to the trust were 44.3 mmboe (47.0% oil and natural gas liquids by volume). This amount includes 18.6 mmboe
attributable to the PDP Royalty Interest and 25.7 mmboe attributable to the Development Royalty Interest, respectively. Certain of the Producing Wells commenced
production in 2007. Chesapeake is currently the operator of 94% of the wells subject to the PDP Royalty Interest. Chesapeake owns an average 52.8% net revenue
interest in the wells subject to the PDP Royalty Interest. The reserves attributable to the trust’s royalty interests include the reserves that are expected to be produced
from the Colony Granite Wash during the 20-year period in which the trust owns the royalty interests as well as the residual interest in the reserves that the trust will sell
on or shortly following the Termination Date.
Overview of the Colony Granite Wash
The Colony Granite Wash is a subset of the greater Granite Wash plays of the Anadarko Basin. The Colony Granite Wash is situated at the eastern end of a
series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko basin, approximately 60 miles into the Texas Panhandle. These
granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the
Colony Granite Wash are encountered between approximately 11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of
Colony Granite Wash ‘A’) and the top of the Prue formation (or base of Colony Granite Wash ‘C’). The individual productive members within the Colony Granite
Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The
Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. However, oil and natural gas liquids production
generates more revenue than natural gas production in the Colony Granite Wash due to prices that have historically been, and currently are, significantly higher for oil
and natural gas liquids than for natural gas. Development costs for horizontal wells drilled and completed in the AMI average approximately $8.31 per boe, which is
comparable to the development costs for other large-scale resource developments in the Mid-Continent in which Chesapeake operates.
Chesapeake began drilling horizontal wells in the Colony Granite Wash in 2007. Chesapeake is the largest leaseholder in the Colony Granite Wash, with
approximately 61,100 net acres (of which 28,700 net acres will initially be subject to the trust’s royalty interests), and is also the most active driller, based on rig count,
and the largest producer in the play. Since 2007, there have been 172 Des Moines horizontal wells drilled in the Colony Granite Wash. Of those 172 wells, Chesapeake
has drilled 132 wells and participated in another 35 wells. As of June 30, 2011, there were 15 rigs drilling horizontal wells in the formation, with nine of those rigs
drilling for Chesapeake. While horizontal wells are more expensive than vertical wells, a horizontal well increases the production of hydrocarbons and adds significant
recoverable reserves per well. In addition, an operator can achieve better returns on drilling investments with horizontal drilling because the production from one
horizontal well is equal to the production from several vertical wells. While Chesapeake is the most active company in this play, other operators in the Colony Granite
Wash include publicly-listed companies such as Penn Virginia Corporation, Apache Corporation, QEP Resources, Inc., SM Energy Company and Marathon Oil
Corporation and privately-held companies such as Samson Oil & Gas Limited, Chaparral Energy, Inc. and Ward Petroleum Corporation.
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Historical Results from the Producing Wells
Natural gas and natural gas liquids produced from the Colony Granite Wash, including the Underlying Properties, are gathered by gathering pipelines owned by
Chesapeake Midstream Partners under a contract that expires in approximately 18 years. Natural gas liquids and natural gas are processed at facilities owned by Enogex
under a contract that expires in 2017 and then sold to a number of primary purchasers in the area. Oil produced from the Underlying Properties is gathered by gathering
pipelines and equipment owned by Chesapeake Midstream Development or transported by trucks owned by third parties and sold to Plains. In the event of a loss of its
contracts with Enogex or Plains, Chesapeake believes that the availability of other customers and service providers in the area is sufficient to accommodate such loss.
Chesapeake also believes that the capacity of interstate pipelines is sufficient to accommodate the increased production of oil, natural gas liquids and natural gas
from the Underlying Properties as currently contemplated.
The following table provides revenues and direct operating expenses relating to the Producing Wells for the years ended December 31, 2008, 2009 and 2010 and
the six months ended June 30, 2010 and 2011, derived from the Underlying Properties’ statements of revenues and direct operating expenses included elsewhere in this
prospectus.
2008
Year Ended
December 31,
2009
2010
$ 159,798
$ 123,594
$ 168,347
$ 87,533
Direct operating expenses:
Production expenses excluding ad valorem taxes
Ad valorem taxes
Production taxes
2,867
13
4,604
3,195
14
2,521
5,542
27
3,271
2,385
27
1,903
3,479
—
1,929
Total direct operating expenses
7,484
5,730
8,840
4,315
5,408
$ 152,314
$ 117,864
$ 159,507
$ 83,218
Oil, natural gas liquids and natural gas revenues(a)
Revenues in excess of direct operating expenses
(a)
Six Months Ended
June 30,
2010
2011
(unaudited)
$
$
Oil, natural gas liquids and natural gas revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and
non-affiliate marketing expenses.
65
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Index to Financial Statements
Oil, Natural Gas Liquids and Natural Gas Sales Prices and Production Expenses
The following table sets forth the production, average sales prices and production and post-production expenses (including any applicable taxes) for the
Producing Wells on a historical basis for the years ended December 31, 2008, 2009 and 2010 and the six months ended June 30, 2011, and for the royalty interests on a
pro forma basis for the years ended December 31, 2008, 2009 and 2010 and the six months ended June 30, 2011.
Historical Results for
Producing Wells
2008
Production:
Oil (mbbls)
Natural gas liquids (mboe)
Natural gas (mmcf)
Total production (mboe)
Average sales prices:(b)
Oil (per bbl)
Natural gas liquids (per boe)
Natural gas (per mcf)
Production expenses (per boe)(c)
Production taxes (per boe)(d)
(a)
(b)
(c)
(d)
Pro Forma for Royalty
Interests (a)
Six
Months
Ended
June 30,
2011
Year Ended December 31,
2009
2010
636
900
8,931
3,024
$ 98.29
$ 45.57
$ 6.30
$ 0.95
$ 1.52
923
1,266
13,192
4,387
$
$
$
$
$
60.18
26.64
2.60
0.73
0.57
870
1,494
14,713
4,816
$
$
$
$
$
76.06
36.28
3.26
1.16
0.68
2008
384
642
6,145
2,050
$
$
$
$
$
93.48
42.67
2.78
1.70
0.94
Year Ended December 31,
2009
2010
572
810
8,038
2,722
$
$
$
$
$
Six
Months
Ended
June 30,
2011
98.29
45.47
6.30
—
1.52
831
1,139
11,873
3,948
$
$
$
$
$
60.18
26.64
2.60
—
0.57
783
1,345
13,242
4,335
$
$
$
$
$
76.06
36.28
3.26
—
0.68
346
578
5,531
1,845
$
$
$
$
$
93.48
42.67
2.78
—
0.94
Pro forma figures are calculated as if the conveyances were in effect for the period indicated.
Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
Production expenses include lease operating costs and ad valorem taxes.
Production taxes are generally based upon (i) volume produced and (ii) prices received for production.
Discussion and Analysis of Historical Results from the Producing Wells
Oil, Natural Gas Liquids and Natural Gas Revenues. During the year ended December 31, 2010, oil, natural gas liquids and natural gas revenues were $168.3
million compared to $123.6 million and $159.8 million for the years ended 2009 and 2008, respectively. The $44.7 million increase in revenue from 2009 to 2010 was
primarily due to an increase in the average sales price for oil, natural gas liquids and natural gas from $28.17 to $34.95 per boe and a production increase of 429 mboe.
The $36.2 million decrease in revenue from 2008 to 2009 was primarily due to a decrease in the average sales price for oil, natural gas liquids and natural gas from
$52.83 to $28.17 per boe, offset by a production increase of 1,363 mboe.
During the six months ended June 30, 2011, oil, natural gas liquids and natural gas revenues were $80.4 million compared to $87.5 million for the six months
ended June 30, 2010. The $7.1 million decrease in revenue was primarily due to a decrease in production of 379 mboe offset by an increase in the average sales price
for oil, natural gas liquids and natural gas from $36.03 to $39.21 per boe.
Production Expenses. During the year ended December 31, 2010, production expenses, excluding ad valorem taxes, were $5.6 million compared to $3.2 million
and $2.9 million for the years ended 2009 and 2008, respectively. The year over year increase was primarily due to an increase in the number of producing wells. On a
unit-of-production basis, production expenses were $1.16 per boe in 2010 compared to $0.73 and $0.95 per boe in 2009 and 2008, respectively. The per unit increase
from 2009 to 2010 was primarily the result of increased production expense rates as the U.S. economy emerged from the economic slowdown which occurred during
the second half of 2008 and throughout 2009. The per unit decrease from 2008 to 2009 was primarily the result of decreased production expense rates due to the
economic slowdown throughout 2009.
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During the six months ended June 30, 2011, production expenses, excluding ad valorem taxes, were $3.5 million in 2011 compared to $2.4 million for the six
months ended June 30, 2010. The increase was primarily due to an increase in the number of producing wells. On a unit-of-production basis, production expenses were
$1.70 per boe in the first half of 2011 compared to $0.99 per boe in the first half of 2010. The per unit increase was primarily the result of increased production expense
rates in improving economic conditions.
Production Taxes. During the year ended December 31, 2010, production taxes were $3.3 million compared to $2.5 million and $4.6 million for the years ended
2009 and 2008, respectively. On a unit-of-production basis, production taxes were $0.68 per boe in 2010 compared to $0.57 and $1.52 per boe in 2009 and 2008,
respectively. The $0.8 million increase in production taxes from 2009 to 2010 was primarily due to an increase in the average sales price for oil, natural gas liquids and
natural gas from $28.17 to $34.95 per boe and a production increase of 429 mboe. The $2.1 million decrease in production taxes from 2008 to 2009 was primarily due
to a significant decrease in the average sales price for oil, natural gas liquids and natural gas from $52.83 to $28.17 per boe.
Production taxes were $1.9 million for both the six months ended June 30, 2011 and the six months ended June 30, 2010, or $0.94 and $0.75 per boe,
respectively.
In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas liquids and natural gas prices are
higher.
Properties Related to the Development Royalty Interest
Chesapeake’s average net revenue interest in the oil and natural gas properties underlying the Development Royalty Interest is approximately 52.0%. The
Development Royalty Interest will entitle the trust to receive 50% of the proceeds attributable to Chesapeake’s net revenue interest in future production of oil and
natural gas resulting from the drilling of the Development Wells, with 25% of such proceeds attributable to the Term Development Royalty and 25% of such proceeds
attributable to the Perpetual Development Royalty.
Chesapeake expects to operate approximately 93% of such wells until the completion of its drilling obligation. Until such time as Chesapeake has met its
commitment to drill the Development Wells, Chesapeake will covenant and agree not to drill or complete, and will not permit any other person within its control to drill
or complete, any well or lease acreage included within the AMI for its own account. During the life of the trust, Chesapeake will further agree not to drill or complete,
and will not permit any other person within its control to drill or complete, any well that will have a perforated segment within 600 feet of any perforated interval of any
Development or Producing Well.
Chesapeake may, in its sole discretion, make any acreage in the Development Area that was exchanged for other acreage in AMI subject to the Development
Royalty Interest, so long as the aggregate exchanged acreage does not exceed five percent of the acreage currently subject to the Development Royalty Interest. In
addition, if Chesapeake acquires any additional leases or interests in the AMI, such additional leases or interests may become subject to the Development Royalty
Interest. See “Description of the Royalty Interests—Additional Features of the Royalty Interests” beginning on page 79.
Oil, Natural Gas Liquids and Natural Gas Reserves
Ryder Scott estimated oil, natural gas liquids and natural gas reserves attributable to the Underlying Properties as of June 30, 2011. Numerous uncertainties are
inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered
and the timing of production of the reserves may vary significantly from the original estimates.
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Proved Reserves of the Underlying Properties and Royalty Interests. The following table sets forth certain estimated proved reserves and the PV-10 value as of
June 30, 2011 attributable to the Underlying Properties and the royalty interests, in each case derived from the reserve reports. The reserve reports were prepared by
Ryder Scott in accordance with criteria established by the SEC.
Proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property by the royalty interest assigned to
the trust in each property. The net revenues attributable to the trust’s reserves are net of an assumed level of post-production costs and taxes based on historical results
but have not been reduced by production and development costs, as the trust will not bear those costs. The reserves related to the Underlying Properties include all of
Chesapeake’s proved reserves expected to be economically produced from the Colony Granite Wash during the life of the properties. The reserves and revenues
attributable to the trust’s interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period in which
the trust owns the royalty interests as well as the residual 50% interests in the reserves attributable to the Perpetual Royalties, which the trust will own on the
Termination Date and subsequently sell. The reserve reports are included as Annex A to this prospectus.
Proved Reserves(1)
Natural Gas
Liquids
(mbbl)
Oil
(mbbl)
Natural Gas
(mmcf)
Total
(mboe)
PV-10 Value(2)
(in
thousands)
Underlying Properties:
Developed
Undeveloped
Total
Royalty Interests:
Developed (90%)
Undeveloped (50%)
Total
(1)
2,648
8,290
7,791
18,640
75,689
179,931
23,054
56,919
343,504
510,087
10,938
26,431
255,620
79,973
853,591
2,233
4,002
6,235
8,319
60,536
80,325
18,557
25,709
325,434
485,706
6,235
14,554
140,861
44,266
811,140
The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas liquids and natural gas for the period
from July 1, 2010 through June 1, 2011, without giving effect to derivative transactions, and were held constant for the life of the properties. The prices used in the reserve reports, as
well as Chesapeake’s internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and adjusted for transportation and
regional price differentials and, for the royalty interests, costs of marketing services provided by Chesapeake affiliates, which will not be charged to the trust. The reference prices and
the equivalent weighted average wellhead prices are presented in the table below.
Natural gas
Oil
liquids
Natural gas
(per bbl)
(per bbl)
(per mcf)
Trailing 12-month average (SEC) pricing
$
89.86
$
89.86
$
4.21
Weighted average wellhead prices (Underlying Properties)
$
86.08
$
39.83
$
2.93
Weighted average wellhread prices (royalty interests)
$
86.09
$
39.80
$
2.86
(2)
PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10% (as required by
the SEC), calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted net cash flows,
or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Because the
historical financial information related to the Underlying Properties consists solely of revenues and direct operating expenses and does not include the effect of income taxes, we
expect the PV-10 and Standardized Measure attributable to the Underlying Properties for each period to be the same. Because the trust will not bear federal income tax expense, we
also expect the PV-10 and Standardized Measure attributable to the royalty interests for each period to be the same. Neither PV-10 nor Standardized Measure represents an estimate
of the fair market value of the Underlying Properties or the royalty interests. We and others in our industry use PV-10 as a measure to compare the relative size and value of proved
reserves held by companies without regard to the specific tax characteristics of such entities. PV-10 for the royalty interests has been calculated without deduction for production and
development costs, as the trust will not bear those costs.
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At the Termination Date, the estimated reserves attributable to the Perpetual Royalties, which the trust will own on the Termination Date and subsequently sell,
are 5.0 mmboe. The PV-10 value of such reserves calculated using 12-month trailing SEC pricing as of June 30, 2011 is $9.2 million.
Information concerning historical changes in net proved reserves attributable to the Underlying Properties, and the calculation of the standardized measure of
discounted future net revenues related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus. Chesapeake has not filed
reserve estimates covering the Underlying Properties with any other federal authority or agency.
The Reserve Reports for the Underlying Properties and the Trust’s Royalty Interests
All of the oil, natural gas liquids and natural gas reserves in this registration statement were estimated by Ryder Scott. The process to review and estimate the
reserves began with the reservoir engineering department collecting and verifying all pertinent data, including but not limited to well test data, production data,
historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data was reviewed by various levels of Chesapeake
management for accuracy before consultation with Ryder Scott. Ryder Scott was consulted with regularity during the reserve estimation process to review properties,
assumptions, and any new data available. Internal reserve estimates and methodologies were compared to Ryder Scott’s estimates and methodologies to test the reserve
estimates and conclusions before the reserve estimates were included in this prospectus. Additionally, Chesapeake’s senior management reviewed and approved the
reserve reports contained herein.
Internal Controls. Chesapeake’s Vice President of Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of
Chesapeake’s and the trust’s reserve estimates, is the primary contact with Ryder Scott and received the reserve reports from Ryder Scott. He has a Bachelor of Science
degree in Petroleum Engineering with 35 years of practical industry experience, including 32 years of estimating and evaluating reserve information. In addition, the
Vice President of Reservoir Engineering is a certified professional engineer in the state of Oklahoma and a member of the Society of Petroleum Engineers.
Chesapeake’s Reservoir Engineering Department continually monitors asset performance and makes reserves estimate adjustments, as necessary, to ensure the
most current reservoir information is reflected in reserves estimates. Reserve information includes production histories as well as other geologic, economic, ownership
and engineering data. The department currently has a total of 97 full-time employees, comprised of 58 degreed engineers (10 serving in management capacities) and 37
engineering technicians with a minimum of a four-year degree in mathematics, economics, finance or other business or science field.
Chesapeake maintains a continuous education program for engineers and technicians on new technologies and industry advancements and also offers refresher
training on basic skill sets.
In order to ensure the reliability of reserves estimates, internal controls observed within the reserve estimation process include:
•
No Chesapeake employee’s compensation is tied to the amount of reserves booked.
•
Chesapeake follows comprehensive SEC-compliant internal policies to determine and report proved reserves. Reserves estimates are made by
experienced reservoir engineers or under their direct supervision.
•
The Reservoir Engineering Department reviews all of Chesapeake’s and the trust’s reported proved reserves, including the reserves associated with the
Underlying Properties and the trust, at the close of each quarter.
•
Each quarter, Reservoir Engineering Department managers, the Vice President of Reservoir Engineering, the Senior Vice President of Production and
the Chief Operating Officer review all significant reserves changes and all new proved undeveloped reserves additions.
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Technologies. The reserve reports were prepared using decline curve analysis to determine the reserves of individual Producing Wells. After estimating the
reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset
undeveloped wells in the field. The continuity of the play across the AMI area was established by reviewing electric well logs, geologically mapping the analogous
reservoir and reviewing extensive production data from 111 vertical and 164 horizontal wells. The proven undeveloped locations within the AMI are generally all
offsets to the horizontal wells drilled and producing to date.
Ryder Scott. Ryder Scott, the independent petroleum engineering consultant, estimated all of the proved reserve information in this prospectus, in accordance
with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards
Codification Topic 932, Extractive Activities—Oil and Gas. For the purposes of the reserve reports, Ryder Scott used technical and economic data including, but not
limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in the reserve reports have been
estimated using deterministic methods. Ryder Scott used standard engineering and geosciences methods, or a combination of methods, such as performance analysis
and analogy, that they considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial
portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves
can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and
reservoir characteristics. Ryder Scott’s expertise is in petroleum engineering, geoscience, and petrophysical interpretation, not legal or accounting matters; they are not
accountants, attorneys, or landmen. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data;
therefore, the conclusions from Ryder Scott necessarily represent only informed professional judgment. The titles to the properties have not been examined by Ryder
Scott, nor has the actual degree or type of interest owned been independently confirmed. The data used in Ryder Scott’s estimates were obtained from Chesapeake and
the non-confidential files of Ryder Scott and were accepted as accurate. Supporting geoscience, field performance, and work data are on file in their office. The
qualifications of the technical person at Ryder Scott primarily responsible for overseeing the estimate of the reserves include: 30 years of practical experience in the
estimation and evaluation of petroleum reserves; a registered professional engineer in the state of Texas; and a Bachelor of Science degree in Electrical Engineering.
These qualifications meet or exceed the Society of Petroleum Engineers standard requirements to be a professionally qualified Reserve Estimator and Auditor. Ryder
Scott are independent petroleum engineers, geologists, geophysicists, and petrophysicists; Ryder Scott does not own an interest in these properties and are not employed
on a contingent basis.
Well Locations
Chesapeake has over 200 potential drilling locations within the AMI, based on assumed spacing of four wells per 640-acre section, and may drill some of the
Development Wells on units that encompass land controlled by third-party operators in order to maximize recovery in the field and also maximize the perforated length
of each Development Well drilled. Chesapeake will be credited for drilling one full Development Well if the perforated length of the well is equal to or greater than
3,500 feet and Chesapeake’s net revenue interest in the well is equal to 52.0%. For wells with a perforated length that is less than 3,500 feet, and for wells in which
Chesapeake has a net revenue interest greater than or less than 52.0%, Chesapeake will receive proportionate credit. For instance, if Chesapeake drilled one well in
which it has a 50% net revenue interest, and such well was completed with a perforated length of 3,000 feet, such well would count for purposes of the development
agreement as only 0.82 Development Wells (i.e., 3,000/3,500 x 50%/52.0%). As a result, Chesapeake may be required to drill more or less than 118 Development Wells
in order to complete its drilling obligation.
Additional Information Regarding the Underlying Properties
Drilling Activity. The following table sets forth information with respect to the wells Chesapeake drilled or participated in during the periods indicated. All wells
drilled during the periods shown were development wells. The
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Index to Financial Statements
information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive
wells drilled and quantities or economic value of reserves found. Productive wells consist of producing wells and wells capable of producing, including oil wells
awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing
wells in which Chesapeake has a working interest and net wells are the sum of Chesapeake’s fractional working interests owned in gross wells. Since July 1, 2011,
Chesapeake has drilled and completed six Development Wells and has drilled two additional wells in the AMI that are awaiting completion as of the date of this
prospectus. Assuming the successful completion of these two wells, such wells will count toward the satisfaction of Chesapeake’s drilling obligation.
2010
Gross
2009
Net
Gross
2008
Net
Gross
Net
Development:
Productive
Dry
16
–
11
–
14
–
8
–
19
–
11
–
Total
16
11
14
8
19
11
Productive Wells. The following table sets forth the number of productive wells within the AMI in which Chesapeake owned working interests as of June 30,
2011 and from which Chesapeake will convey the royalty interests to the trust, all of which are classified as natural gas wells.
Gross
Productive Wells
Net
69
45
Developed and Undeveloped Acreage. The following table sets forth information regarding developed and undeveloped acreage held by Chesapeake within the
AMI as of September 30, 2011. Substantially all of the leases associated with the Underlying Properties are held by production and not subject to expiration so long as
production continues in paying quantities.
Developed
Acreage (1)
Gross(3)
Acreage held by Chesapeake within the AMI
41,555
Net(4)
26,445
Undeveloped
Acreage (2)
Gross(3)
Net(4)
3,807
2,215
(1)
Gross and net developed acres are acres spaced or assignable to productive wells. The drilling unit for each Colony Granite Wash horizontal well comprises 640 acres. As such,
developed acreage may include up to 640 acres assigned to each Colony Granite Wash horizontal well. Future drilling opportunities may exist within both our developed and
undeveloped acreage through increased density wells and drilling of proved undeveloped and unproved locations in the same formation, as well as other non-producing formations.
(2)
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless
of whether such acreage contains proved reserves.
(3)
A gross acre is an acre in which Chesapeake owns a working interest. The number of gross acres is the total number of acres in which Chesapeake owns a working interest.
(4)
A net acre is deemed to exist when the sum of Chesapeake’s fractional ownership working interests in gross acres equals one. The number of net acres is the sum of Chesapeake’s
fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Sale and Abandonment of the Underlying Properties
Chesapeake and any transferee will have the right to abandon its interest in any well or property comprising a portion of the Underlying Properties if Chesapeake
determines in good faith and in accordance with the Reasonably Prudent Operator Standard that such well or property ceases to produce, or is not capable of producing,
oil, natural gas liquids or natural gas in commercially paying quantities. Upon termination of the lease, that portion of the royalty interests relating to the abandoned
property will be extinguished. See “Description of the Royalty Interests—Additional Features of the Royalty Interests—Abandonment of Underlying Properties” on
page 81.
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Following the satisfaction of its drilling obligation, Chesapeake generally may, without the consent or approval of the trust unitholders, sell all or a portion of its
interests in the Underlying Properties. In any such sale by Chesapeake, the Underlying Properties must be sold subject to and burdened by the royalty interests, except
that Chesapeake may require the trust to release the trust’s royalty interests on such Underlying Properties with an aggregate value to the trust not to exceed $5.0 million
during any 12-month period. In such event, the trust must receive an amount equal to the fair value to the trust of any royalty interests it sells. See “Description of the
Royalty Interests—Additional Features of the Royalty Interests—Sale and Release of Underlying Properties” on page 81.
Marketing and Post-Production Services
Pursuant to the terms of the conveyances creating the royalty interests, Chesapeake will have the responsibility to market, or cause to be marketed, the oil,
natural gas liquids and natural gas production related to the Underlying Properties. While marketing costs of non-affiliates of Chesapeake may be deducted from the
proceeds upon which the royalty payments will be calculated, the terms of the conveyances creating the royalty interests do not permit Chesapeake or any of its
affiliates to include their own marketing costs in any such deductions. As a result, the proceeds to the trust from the sales of oil, natural gas liquids and natural gas
production from the Underlying Properties will be determined based on the same price (net of post-production expenses and severance taxes) that Chesapeake receives
from third parties for oil, natural gas liquids and natural gas production attributable to Chesapeake’s remaining interest in the Underlying Properties.
Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, markets the majority of Chesapeake’s operated production. CEMI
enters into oil, natural gas liquids and natural gas sales arrangements with large aggregators of supply and these arrangements may be on a month-to-month basis or
may be for a term of up to one year or longer. The oil, natural gas liquids and natural gas are sold at market prices and subsequently any applicable post-production
expenses will be deducted. CEMI sells production from the Underlying Properties to a diverse group of aggregators, the identity of which changes from time to time.
Post-production expenses will be deducted from proceeds paid to the trust. Chesapeake Midstream Partners and Chesapeake Midstream Development will
provide post-production services, including gathering, treating and compression, while third parties, including Enogex and Plains, will provide processing,
transportation and other post-production services. The proceeds paid to the trust will be reduced by Chesapeake’s deductions for these post-production expenses.
However, the trust will not be responsible for costs of marketing services provided by Chesapeake or any of its affiliates.
Post-production expenses may be deducted by the ultimate purchaser of the oil, natural gas liquids and natural gas prior to payment being made to Chesapeake or
CEMI for such production. At other times, Chesapeake or CEMI will make payments directly to the applicable provider of such post-production services. In either
instance, the trust’s cash available for distribution will be reduced by the costs incurred by Chesapeake or CEMI for such post-production services. If the
post-production expenses are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is
less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the royalty interest are reduced accordingly.
The cost of post-production services is included within the assumed differentials from NYMEX pricing discussed above under “Target Distributions and
Subordination and Incentive Thresholds” beginning on page 50.
Post-production expenses may increase or decrease in the future. The post-production expenses attributable to third-party arrangements will be negotiated based
on market conditions at the time or pursuant to a state or federal regulatory proceeding. Chesapeake will be permitted to deduct from the proceeds available to the trust
other post-production expenses necessary to enhance the value of the oil, natural gas liquids and natural gas from the Underlying Properties and to transport such
production to market.
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Chesapeake expects to enter into oil, natural gas liquids and natural gas supply arrangements and post-production service arrangements for the oil, natural gas
liquids and natural gas to be produced from the Development Wells that are similar to those in place with respect to the Producing Wells. Any new oil, natural gas
liquids and natural gas supply arrangements or those entered into for providing post-production services, will be utilized in determining the proceeds for the Underlying
Properties.
Title to Properties
The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect
Chesapeake’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and
in estimating the size and the value of the reserves attributable to the royalty interests.
Chesapeake acquired its interests in the Underlying Properties through a variety of means, including through the acquisition of oil and natural gas leases by
Chesapeake directly from the mineral owner, through assignments of oil and natural gas leases to Chesapeake by the lessee who originally obtained the leases from the
mineral owner, through farmout agreements that grant Chesapeake the right to earn interests in the properties covered by such agreements by drilling wells, and through
acquisitions of other oil and natural gas interests by Chesapeake.
Chesapeake’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more
of the following:
•
royalties and other burdens, express and implied, under oil and natural gas leases;
•
production payments and similar interests and other burdens created by Chesapeake or its predecessors in title;
•
a variety of contractual obligations arising under operating agreements, farmout agreements, production sales contracts and other agreements that may
affect the properties or their titles;
•
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and
contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith;
•
pooling, unitization and communitization agreements, declarations and orders;
•
easements, restrictions, rights-of-way and other matters that commonly affect real property;
•
conventional rights of reassignment that obligate Chesapeake to reassign all or part of a property to a third party if Chesapeake intends to release or
abandon such property; and
•
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties;
•
customarily acceptable title defects that (a) do not result in another person’s superior claim of title to the relevant Underlying Properties or (b) are not
such as to (in the aggregate) interfere materially with the operation, value or use of the Underlying Properties; and
•
other liens, charges, encumbrances, contracts, agreements, instruments, obligations, conditions, reservations, burdens, defects and irregularities
affecting the Underlying Properties that (a) do not secure an obligation in respect of borrowed money and (b) are not such as to (in the aggregate)
interfere materially with the operation, value or use of the Underlying Properties.
Chesapeake believes that the burdens and obligations affecting the Underlying Properties and the royalty interests are conventional in the industry for similar
properties. Chesapeake also believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not
materially adversely affect the value of the royalty interests.
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Chesapeake will record the conveyance of the royalty interests in the real property records of Washita County, Oklahoma and, if necessitated by an expansion of
the AMI, in Custer County, Oklahoma. Chesapeake and the trust believe that the recordation of the conveyance of the royalty interests in the appropriate real property
records in Oklahoma will constitute the conveyance of fully vested real property interests under Oklahoma law or interests in hydrocarbons in place or to be produced
under Oklahoma law. Oklahoma law, however, is not entirely clear as to whether an overriding royalty interest is a real property interest. While the Oklahoma Supreme
Court has recently held that royalty interests are real property interests, such cases did not expressly overturn prior Oklahoma Supreme Court cases holding that an
overriding royalty interest was not necessarily a real property interest. In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that
will convey the royalty interests to the trust, if a bankruptcy court held that (a) the royalty interests did not constitute fully vested real property interests or interests in
hydrocarbons in place or to be produced or (b) the royalty interests were not otherwise eligible to be excluded from the bankruptcy estate under federal bankruptcy law,
the royalty interests may be treated as unsecured claims of the trust against Chesapeake. If that were the case, creditors of Chesapeake would be able to claim the
royalty interests as an asset of the bankruptcy estate to be sold to satisfy obligations to them and the trust could lose the entire value of the royalty interests to senior
creditors of Chesapeake.
Chesapeake believes that its title to the Underlying Properties is, and the trust’s title to the royalty interests will be, good and defensible in accordance with
standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such
properties or royalty interests. Prior to the drilling of a Development Well, Chesapeake expects to obtain a drilling title opinion to identify defects in title to the
leasehold. Chesapeake’s in-house legal department frequently issues drilling title opinions for the company’s leasehold, which title opinions are written to the
Oklahoma Title Examination Standards published by the Real Property Law Section of the Oklahoma Bar Association. Frequently, as a result of such examinations,
certain curative work must be done to correct identified title defects, and such curative work entails time and expense. Chesapeake will not be relieved of its obligation
to drill a well if such title examination prior to drilling reveals a title defect preventing Chesapeake from drilling in such drill site. Chesapeake will also be obligated to
provide the trust with a true-up for any breach of Chesapeake’s warranty of title in the conveyance to the trust of the royalty interests that is discovered after the
conveyance to the trust. See “Description of the Royalty Interests—Additional Features of the Royalty Interests—True-up” on page 80.
Competition and Markets
The oil and natural gas industry is highly competitive. Chesapeake competes with both major integrated and other independent oil, natural gas liquids and natural
gas companies in acquiring desirable leasehold acreage, producing properties and the equipment and expertise necessary to explore, develop and operate its properties
and market its production. Some of Chesapeake’s competitors may have larger financial and other resources than Chesapeake. The oil, natural gas liquids and natural
gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquified natural gas. Competitive conditions
may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. In addition, some of Chesapeake’s larger
competitors may have a competitive advantage when responding to factors that affect demand for oil, natural gas liquids and natural gas production, such as changing
prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of pipelines and other
transportation facilities, and overall economic conditions. Chesapeake believes that its technological expertise, its exploration, land, drilling and production capabilities
and the experience of its management generally enable it to compete effectively.
Future price fluctuations for oil, natural gas liquids and natural gas will directly impact trust distributions, estimates of reserves attributable to the trust’s
interests, and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil, natural gas liquids and
natural gas, neither the trust nor Chesapeake can make reliable predictions of future supply and demand for oil, natural gas liquids and natural gas, future oil, natural gas
and natural gas liquids prices or the effect of future oil, natural gas liquids and natural gas prices on the trust.
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Regulation
General. All of Chesapeake’s operations are conducted onshore in the United States. The U.S. natural gas and oil industry is regulated at the federal, state and
local levels, and some of the laws, rules and regulations that govern its operations carry substantial penalties for noncompliance. These regulatory burdens increase
Chesapeake’s cost of doing business and, consequently, affect its profitability.
Regulation of Natural Gas and Oil Operations. Chesapeake’s exploration and production operations are subject to various types of regulation at the U.S. federal,
state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as
bonds) covering drilling and well operations. Other activities subject to regulation include, but are not limited to:
•
the location of wells;
•
the method of drilling and completing wells;
•
the surface use and restoration of properties upon which wells are drilled;
•
water withdrawal;
•
the plugging and abandoning of wells;
•
the disposal of fluids used or other wastes generated in connection with operations;
•
the marketing, transportation and reporting of production; and
•
the valuation and payment of royalties.
Chesapeake’s operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the
density of wells that may be drilled in a particular area) and the unitization or pooling of natural gas and oil properties. In this regard, some states, such as Oklahoma,
allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas and New Mexico, rely on voluntary pooling of lands and
leases. In areas where pooling is voluntary, it may be more difficult to form units and therefore, more difficult to fully develop a project if the operator owns less than
100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or
flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil, natural gas
liquids and natural gas Chesapeake can produce and to limit the number of wells and the locations at which it can drill.
Chesapeake operates a number of natural gas gathering systems. The U.S. Department of Transportation and certain state agencies regulate the safety and
operating aspects of the transportation and storage activities of these facilities. There is currently no price regulation of the company’s sales of oil, natural gas liquids
and natural gas, although governmental agencies may elect in the future to regulate certain sales.
Chesapeake does not anticipate that compliance with existing laws and regulations governing exploration, production and natural gas gathering will have a
material adverse effect upon its capital expenditures, earnings or competitive position.
Environmental, Health and Safety Regulation. The business operations of Chesapeake and its ownership and operation of oil, natural gas liquids and natural gas
interests are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials
into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or
otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. Chesapeake must take
into account the cost of complying with environmental regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface
facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and
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production wastes, and the protection of water and air. In addition, Chesapeake’s operations may require it to obtain permits for, among other things,
•
air emissions;
•
the construction and operation of underground injection wells to dispose of produced saltwater and other non-hazardous oilfield wastes; and
•
the construction and operation of surface pits to contain drilling muds and other non-hazardous fluids associated with drilling operations.
Delays in obtaining permits, an inability to obtain new permits or revocation of Chesapeake’s current permits due to noncompliance could result in the
imposition of fines and could inhibit Chesapeake’s ability to drill the Development Wells or continue production from the Producing Wells.
Federal, state and local laws may require Chesapeake to remove or remediate previously disposed wastes, including wastes disposed of or released by
Chesapeake or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial
well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response,
Compensation, and Liability Act, or CERCLA, and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on
classes of persons who are considered responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site
where the release occurred, and persons that disposed of or arranged for the disposal of hazardous substances at the site. CERCLA and analogous state laws also
authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and
to seek to recover from responsible classes of persons the costs of such actions.
Other federal and state laws, in particular the federal Resource Conservation and Recovery Act, or RCRA, regulate hazardous and non-hazardous solid wastes.
In the course of its operations, Chesapeake generates petroleum hydrocarbon wastes and ordinary industrial wastes. Under a longstanding legal framework, certain of
these wastes are not subject to federal regulations governing hazardous wastes, though they may be regulated under other federal and state laws. Chesapeake believes it
is in substantial compliance with all regulations regarding the handling and disposal of oil and gas exploration and production wastes from its operations, including with
respect to the Underlying Properties. These wastes may in the future be designated as hazardous wastes and may thus become subject to more rigorous and costly
compliance and disposal requirements. Such additional regulation could have a material adverse effect on the cash distributions to the trust unitholders.
Federal and state occupational safety and health laws require Chesapeake to organize and maintain information about hazardous materials used, released or
produced in its operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. Chesapeake
is also subject to the requirements and reporting set forth in federal workplace standards.
Chesapeake has made and will continue to make expenditures to comply with environmental, health and safety regulations and requirements. These are
necessary business costs in the oil and natural gas industry. Although Chesapeake is not fully insured against all environmental, health and safety risks, and
Chesapeake’s insurance does not cover any penalties or fines that may be issued by a governmental authority, it maintains insurance coverage which it believes is
customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and
regulations, as well as claims for damages to property or persons, resulting from company operations, could result in substantial costs and liabilities, including civil and
criminal penalties, to Chesapeake. Chesapeake believes that it is in material compliance with existing environmental, health and safety regulations. It believes that the
cost of maintaining compliance with these existing regulations will not have a material adverse effect on its business, financial position and results of operation, but new
or more stringent regulations could increase the cost of doing business and could have a material adverse effect on the proceeds available to the trust. Moreover,
accidental
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releases or spills may occur in the course of Chesapeake’s operations on the Underlying Properties causing Chesapeake to incur significant costs and liabilities,
including for third-party claims for damage to property and natural resources or personal injury.
Hydraulic Fracturing. Vast quantities of oil, natural gas liquids and natural gas deposits exist in deep shale and other formations. It is customary in
Chesapeake’s industry to recover oil, natural gas liquids and natural gas from these deep shale formations through the use of hydraulic fracturing, combined with
sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and
other additives are pumped under high pressure into the formation. These formations are generally geologically separated and isolated from fresh ground water supplies
by protective rock layers. Chesapeake’s well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are
specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers.
Legislative, regulatory, guidance and enforcement efforts at the federal level and in some states have been initiated to require or make more stringent the
permitting and compliance requirements for hydraulic fracturing operations. Hydraulic fracturing is typically regulated by state oil and gas commissions. However, the
EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control
Program and has begun the process of drafting guidance documents for permitting authorities and the industry on the process for obtaining a permit for hydraulic
fracturing involving diesel fuel. Industry groups have filed suit challenging the EPA’s assertion of authority as improper rule making. At the same time, the EPA has
commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. The
results of EPA’s guidance, including its definition of diesel fuel, the related litigation, EPA’s study, and other analyses by federal and state agencies to assess the
impacts of hydraulic fracturing could each spur further action toward federal legislation and regulation of hydraulic fracturing activities. Also, for the second
consecutive session, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used
in the fracturing process. While some states have adopted regulations that could restrict hydraulic fracturing in certain circumstances, Oklahoma’s regulations recently
received positive approval from the State Review of Oil & Natural Gas Environmental Regulations and, as such, the agency has not undertaken further rulemaking. If
new laws or regulations that significantly restrict hydraulic fracturing are adopted at the Oklahoma state level, such legal requirements could make it more difficult or
costly for Chesapeake to perform fracturing to stimulate production in the Underlying Properties and thereby affect the determination of whether a well is commercially
viable. In addition, if hydraulic fracturing is regulated at the federal level, Chesapeake’s fracturing activities, including with respect to its operations at the Underlying
Properties, could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs.
Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas liquids and natural gas that Chesapeake is ultimately able to produce in commercial
quantities from the Underlying Properties.
Climate Change. Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating
new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA
has already made findings and issued regulations that require Chesapeake to establish and report an inventory of greenhouse gas emissions and that could lead to the
imposition of restrictions on greenhouse gas emissions from stationary sources such as Chesapeake’s. Legislative and regulatory proposals for restricting greenhouse
gas emissions or otherwise addressing climate change could require Chesapeake to incur additional operating costs and could adversely affect demand for the oil,
natural gas liquids and natural gas that it sells. The potential increase in Chesapeake’s operating costs could include new or increased costs to obtain permits, operate
and maintain its equipment and facilities, install new emission controls on its equipment and facilities, acquire allowances to authorize its greenhouse gas emissions,
pay taxes related to its greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use
alternative energy sources could reduce demand for oil, natural gas liquids and natural gas.
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DESCRIPTION OF THE ROYALTY INTERESTS
The royalty interests will be conveyed to the trust by Chesapeake by means of conveyance instruments that will be recorded in the appropriate real property
records in Washita County, Oklahoma.
The royalty interests will be conveyed from Chesapeake’s interest in the Underlying Properties effective as of July 1, 2011. The PDP Royalty Interest entitles the
trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production expenses and any applicable taxes) from the
sale of production of oil, natural gas liquids and natural gas attributable to Chesapeake’s net revenue interest in the Producing Wells. The Development Royalty Interest
entitles the trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production expenses and any applicable
taxes) from the sale of production of oil, natural gas liquids and natural gas attributable to Chesapeake’s net revenue interest in the Development Wells.
Generally, the percentage of production proceeds to be received by the trust with respect to a well will equal the product of (a) the percentage of proceeds to
which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the Development Wells) multiplied by (b) Chesapeake’s net
revenue interest in the well. Chesapeake on average owns a 52.8% net revenue interest in the Producing Wells. Therefore, the trust will have an average 47.5% net
revenue interest in the Producing Wells. Chesapeake on average owns a 52.0% net revenue interest in the properties on which it expects to drill the Development Wells
and based on this net revenue interest, the trust would have an average 26.0% net revenue interest in the Development Wells. Chesapeake’s actual net revenue interest
in any particular Producing Well or Development Well (or the average net revenue interest as a whole) may differ from these averages.
PDP Royalty Interest
The PDP Royalty Interest entitles the trust to receive an amount of cash for each calendar quarter equal to 90% of the proceeds (exclusive of any production or
development costs but after deducting post-production expenses and any applicable taxes) from the sale of oil, natural gas liquids and natural gas production attributable
to Chesapeake’s net revenue interest in the Producing Wells. Proceeds from the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake’s
net revenue interest in the Producing Wells in any calendar quarter means, for any calendar quarter commencing on or after July 1, 2011, the amount calculated based
on actual production volumes attributable to Chesapeake’s net revenue interest in the Producing Wells, in each case after deducting the trust’s proportionate share of:
•
any taxes levied on the severance or production of the oil, natural gas liquids and natural gas produced from the Producing Wells and any property
taxes attributable to the oil, natural gas liquids and natural gas produced from the Producing Wells; and
•
post-production expenses, which will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the
oil, natural gas liquids and natural gas produced, as applicable (excluding costs for marketing services provided by Chesapeake).
Proceeds payable to the trust from the sale of oil, natural gas liquids and natural gas production attributable to the Producing Wells in any calendar quarter will
not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production
of oil, natural gas liquids and natural gas attributable to the Producing Wells, including any costs to drill, complete or plug and abandon a Producing Well. Additionally,
costs associated with water production, handling, treatment and disposal, the installation of artificial lift equipment and any further completion activities, such as
re-fracturing a well, will be borne by the operator of the well.
Development Royalty Interest
The Development Royalty Interest entitles the trust to receive an amount of cash for each calendar quarter equal to 50% of the proceeds (exclusive of any
production or development costs but after deducting post78
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production expenses and any applicable taxes) from the sale of estimated oil, natural gas liquids and natural gas production attributable to Chesapeake’s net revenue
interest in the Development Wells. Proceeds from the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake’s net revenue interest in the
Development Wells in any calendar quarter means, for any calendar quarter commencing on or after July 1, 2011, the amount calculated based on actual production
volumes attributable to Chesapeake’s net revenue interest in the Development Wells, in each case after deducting the trust’s proportionate share of:
•
any taxes levied on the severance or production of the oil, natural gas liquids and natural gas produced from the Development Wells and any property
taxes attributable to the oil, natural gas liquids and natural gas produced from the Development Wells; and
•
post-production expenses, which will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the
oil, natural gas liquids and natural gas produced, as applicable (excluding costs for marketing services provided by Chesapeake).
Proceeds payable to the trust from the sale of oil, natural gas liquids and natural gas production attributable to the Development Wells in any calendar quarter
will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the
production of oil, natural gas liquids and natural gas attributable to the Development Wells, including any costs to drill, complete or plug and abandon a Development
Well. Additionally, costs associated with water production, handling, treatment and disposal, the installation of artificial lift equipment and any further completion
activities, such as re-fracturing a well, will be borne by the operator of the well.
Sale of the Perpetual Royalties
The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert
to Chesapeake at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date
or soon thereafter. Chesapeake will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.
The trust agreement provides that the trustee will use commercially reasonable efforts to retain a third-party advisor to market the Perpetual Royalties within 30
business days of the Termination Date. If the trustee receives a bona fide offer from a proposed purchaser other than Chesapeake and wants to sell all or part of the
Perpetual Royalties, it will be required to give notice (the “Offer Notice”) to Chesapeake, identifying the proposed purchaser and setting forth the proposed sale price,
payment terms and other material terms and conditions under which the trustee is proposing to sell. Chesapeake would then have 30 days from receipt of the Offer
Notice to elect, by notice to the trustee, to purchase the subject properties offered for sale on the terms and conditions set forth in the Offer Notice. If Chesapeake makes
such election, the proposed purchaser would be entitled to receive reimbursement of its reasonable and documented expenses incurred in connection with its review and
analysis of the subject properties and bid preparation. Chesapeake and the trust would share equally the cost of reimbursement to the proposed purchaser.
If Chesapeake does not give notice within the 30-day period following the Offer Notice, the trustee may sell such properties to the identified purchaser on terms
and conditions that are substantially the same as those previously set forth in such Offer Notice. Moreover, if, after a reasonable marketing period, no bid is received on
any or all of the Perpetual Royalties from any party other than Chesapeake, then Chesapeake shall obtain, at the trust’s expense, and deliver to the trustee, a fairness
opinion from a nationally recognized valuation firm with expertise in valuing oil, natural gas liquids and natural gas properties stating that the proposed sale price to be
paid by Chesapeake to the trust for the properties is fair to the trust.
Additional Features of the Royalty Interests
Reasonably Prudent Operator Standard. In performing certain of its obligations under the conveyance instruments, including marketing production, contracting
for post-production services and operating the Producing Wells and Development Wells, Chesapeake is required to adhere to the Reasonably Prudent Operator
Standard. Where Chesapeake does not operate the Underlying Properties, Chesapeake is required to use
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commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying Properties to adhere to the Reasonably Prudent Operator
Standard and to cause such operators to only drill Development Wells on locations classified as proven undeveloped at the time of drilling.
True-up. In the conveyances for the PDP Royalty Interest, Chesapeake warrants to the trust that the trust will receive a specified amount of net revenue interest
in respect of a Producing Well. In the conveyances for the Development Royalty Interest, Chesapeake warrants to the trust that the trust will receive a net revenue
interest in respect of a Development Well that will not be less than the net revenue interest used to calculate Chesapeake’s satisfaction of its drilling obligation for such
well. Chesapeake’s actual net revenue interest in a well may be greater or less than the net revenue interest warranted to the trust in the conveyances for various reasons,
including mistakes in the record title documents or mistakes in identifying mineral interest owners when leasing properties.
If Chesapeake determines that its actual net revenue interest with respect to a Producing Well or Development Well is less than the net revenue interest
warranted to the trust in the conveyances relating to such well, the trust will continue to receive payments based on the net revenue interest warranted in the
conveyances and Chesapeake’s retained interest in such well will be reduced to the extent required to allow the trust to receive a royalty interest based on the net
revenue interest warranted in the conveyances. If Chesapeake were to have an insufficient retained interest in a well out of which to make the foregoing true-up, then
Chesapeake would be required to pay to the trust with respect to such well an amount equal to the difference between the payments the trust actually receives from the
royalty interests in such well and the payments the trust would have received from such well had Chesapeake’s actual net revenue interest been the amount warranted in
the conveyances. Any true-up payment must be paid from proceeds attributable to production from the Underlying Properties.
By way of example, if Chesapeake’s net revenue interest warranted in the conveyances as to a Development Well were 50%, the trust would receive a net
revenue interest of 25% in such well. If Chesapeake later determined that its actual net revenue interest as to such well was only 40%, resulting in the trust’s holding
only a 20% net revenue interest in the well, Chesapeake would reduce its retained interest in the well by 5% to provide the trust with the net revenue interest in the well
warranted in the conveyances (i.e., 20% actual net revenue interest + 5% true-up by Chesapeake = 25% net revenue interest).
If Chesapeake determines that its actual net revenue interest with respect to a well is greater than the net revenue interest warranted to the trust in the
conveyances as to such well, the trust will continue to receive royalty payments based on the net revenue interest warranted in the conveyances and Chesapeake will not
receive any additional credit for such well in respect of its drilling obligation.
If Chesapeake sells any of its revenue interests in the Underlying Properties, the buyer will assume the true-up obligations with respect to the properties
purchased by it.
Controversies. If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:
•
amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;
•
amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have
been received until disbursed to it by the escrow agent; and
•
amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.
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Overpayments. The trustee is not obligated to return any cash received from the royalty interests. Any overpayments made to the trust by Chesapeake due to
adjustments to prior calculations of proceeds or otherwise will reduce future amounts payable to the trust until Chesapeake recovers the overpayments.
Sale and Release of Underlying Properties. The conveyances provide that Chesapeake may not sell any of the Underlying Properties subject to the royalty
interests until it has satisfied the drilling obligation pursuant to the terms of the development agreement. After the satisfaction of its drilling obligation, the conveyances
generally permit Chesapeake to sell, without the consent or approval of the trust unitholders, all or any part of its retained interest in the Underlying Properties, if such
Underlying Properties are sold subject to and burdened by the royalty interests. The trust unitholders are not entitled to any proceeds of any sale of Chesapeake’s
interest in the Underlying Properties that remains subject to and burdened by the royalty interests. Following such sale, the royalties attributable to the transferred
property will be calculated as described in this prospectus, and paid by the purchaser or transferee to the trust. As a result, any additional costs resulting from the sold
property will not reduce the proceeds paid to the trust from the Underlying Properties retained by Chesapeake. Chesapeake will require any purchaser of any of the
Underlying Properties to enter into an agreement to perform Chesapeake’s obligations under the administrative services agreement with respect to those properties.
In addition, following the satisfaction of its drilling obligation, Chesapeake may, without the consent of the trust unitholders, require the trust to release for sale
royalty interests with an aggregate value to the trust not to exceed $5.0 million during any 12-month period. These releases will be made only in connection with a sale
by Chesapeake of a portion of the Underlying Properties to a non-affiliate and are conditioned upon the trust receiving an amount equal to the fair value to the trust of
such royalty interests. Any net sales proceeds paid to the trust in respect of any such released Underlying Properties are distributable to trust unitholders for the quarter
in which they are received. Chesapeake has not identified for sale any of the Underlying Properties.
Exchange and Addition of Acreage. Chesapeake may at its option at any time prior to the completion of its drilling obligation cause the trust to exchange leased
acreage subject to the royalty interests, free and clear of such royalty interests, for other leased acreage within the Development Area, and cause such leased acreage
exchanged to the trust to be made subject to the royalty interests as set forth in the conveyances. Following such an exchange, the exchange acreage in the Development
Area will be included in the AMI for all purposes of the development agreement, and the corresponding acreage in the AMI exchanged therewith will be excluded from
the AMI for all purposes of the development agreement. In addition, in the event Chesapeake acquires any additional leases or interests in the AMI (other than renewals
or extensions) prior to the completion of its drilling obligation, Chesapeake may at its option make such additional leases or interests subject to the royalty interests with
respect to any Development Wells subsequently drilled on such acreage. In no event, however, may any exchange of acreage or any addition of leased acreage or
interests be effected unless Chesapeake certifies to the trust that, among other things, all of the aggregate acreage attributable to the exchanged leases or additional
leases or interests does not exceed five percent of the acreage initially subject to the royalty interests and that, with respect to exchange acreage, the reasonable quantity
of proved undeveloped reserves of such exchange acreage does not differ significantly from the reasonable quantity of proved undeveloped reserves being exchanged
for such acreage, and, with respect to additional leases or interests, the reserve profile of such acreage is consistent with the reserve profile of the acreage that would be
developed in the absence of such additional acreage.
Abandonment of Underlying Properties. Chesapeake and any transferee will have the right to abandon its interest in any well or property comprising a portion of
the Underlying Properties if Chesapeake determines in good faith and in accordance with the Reasonable Prudent Operator Standard that such well or property ceases to
produce, or is not capable of producing, oil, natural gas liquids or natural gas in commercially paying quantities. Where Chesapeake does not operate the Underlying
Properties, Chesapeake is required to use commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying Properties to
adhere to the Reasonably Prudent Operator Standard. Upon termination of the lease, that portion of the royalty interests relating to the abandoned property will be
extinguished.
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Maintenance of Books and Records. Chesapeake must maintain books and records sufficient to determine the amounts payable for the royalty interests to the
trust. Quarterly and annually, Chesapeake must deliver to the trustee a statement of the computation of the proceeds for each computation period as well as quarterly
drilling and production results. See “Where You Can Find More Information” beginning on page 119.
Reservation of Rights. Pursuant to the conveyances, Chesapeake will expressly except and reserve all right, title and interest in and to any well and appurtenant
production facilities not expressly conveyed to the trust.
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DESCRIPTION OF THE TRUST AGREEMENT
Creation and Organization of the Trust; Amendments
The trust was created under Delaware law as a separate legal entity to acquire and hold the royalty interests for the benefit of the trust unitholders pursuant to an
agreement among Chesapeake, the trustee and the Delaware trustee. The royalty interests are passive in nature and neither the trust nor the trustee has any control over,
or responsibility for, costs relating to the operation of the Underlying Properties. Neither Chesapeake nor other operators of the Underlying Properties have any
contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties
other than the obligations of Chesapeake to drill the Development Wells. After the conveyance of the royalty interests, however, Chesapeake will retain an interest in
each of the Underlying Properties. For a description of the Underlying Properties and other information relating to them, see “The Underlying Properties” beginning on
page 64.
The trust agreement will provide that the trust’s business activities will generally be limited to owning the royalty interests, being a party to the hedging
arrangements and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the royalty interests. As a
result, the trust will not be permitted to acquire other oil, natural gas liquids and natural gas properties or royalty interests except as otherwise discussed under
“Description of the Royalty Interests—Additional Features of the Royalty Interests” beginning on page 79. Additionally, following the completion of this offering, the
trust will not be able to issue any additional trust units.
The beneficial interests in the trust are divided into 45,750,000 trust units. Each trust unit represents an equal undivided beneficial interest in the property of the
trust. Please read “Description of the Trust Units” beginning on page 89 for additional information concerning the trust units.
Amendment of the trust agreement generally requires the vote of holders of a majority of the trust units and a majority of the common units (excluding common
units owned by Chesapeake and its affiliates) voting in person or by proxy at a meeting of such unitholders at which a quorum is present. At any time that Chesapeake
and its affiliates collectively own less than 10% of the outstanding trust units, however, the standard for approval will be the vote of a majority of the trust units,
including units owned by Chesapeake, voting in person or by proxy at a meeting of the unitholders at which a quorum is present. Abstentions and broker non-votes shall
not be deemed to be a vote cast. However, no amendment may:
•
increase the power of the trustee to engage in business or investment activities;
•
decrease the incentive threshold or increase the subordination threshold or change the portion of the quarterly cash distributions payable as an incentive
distribution;
•
alter the rights of the trust unitholders as among themselves; or
•
permit the trustee to distribute the royalty interests in kind.
Amendments to the trust agreement’s provisions addressing the following matters may not be made without Chesapeake’s consent:
•
dispositions of the trust’s assets;
•
indemnification of the trustee;
•
reimbursement of out-of-pocket expenses of Chesapeake when acting as the trust’s agent;
•
termination of the trust; and
•
amendments of the trust agreement.
Certain amendments to the trust agreement do not require the vote of the trust unitholders. See “—Permitted Amendments” on page 86.
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The business and affairs of the trust will be managed by the trustee. The trustee will have no ability to manage or influence the operations of the Underlying
Properties. Chesapeake currently operates 94% of the Producing Wells and expects to operate approximately 93% of the Development Wells until the completion of its
drilling obligation, but will have no ability to manage or influence the operations of the trust, except through its limited voting rights as a holder of trust units.
Assets of the Trust
Upon completion of this offering, the principal assets of the trust will consist of the PDP Royalty Interest and the Development Royalty Interest, the
development agreement, the Drilling Support Lien, the administrative services agreement, the hedging arrangements and any cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to the trust unitholders. See “The Trust” beginning on page 44 for more information.
Duties and Powers of the Trustee; Liability of the Trustee
The duties and powers of the trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The
trust agreement provides that the trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the trust agreement and the
duties and liabilities of the trustee as set forth in the trust agreement replace any other duties and liabilities, including fiduciary duties, to which the trustee might
otherwise be subject.
The trustee’s principal duties consist of:
•
collecting cash proceeds attributable to the royalty interests;
•
paying expenses, charges and obligations of the trust from the trust’s assets;
•
receiving and making payments under the hedging arrangements;
•
determining whether cash distributions exceed subordination or incentive thresholds, and making cash distributions to the unitholders and Chesapeake
(with respect to incentive distributions) in accordance with the trust agreement;
•
causing to be prepared and distributed a Schedule K-1 for each trust unitholder and to prepare and file tax returns on behalf of the trust; and
•
causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities
exchange or quotation system on which the trust units are listed or admitted to trading.
Chesapeake will provide administrative and other services to the trust in fulfillment of certain of the foregoing duties pursuant to the administrative services
agreement.
The trustee may create a cash reserve to pay for future expenses of the trust. If the trustee determines that the cash on hand and the cash to be received are
insufficient to cover the trust’s expenses, the trustee may cause the trust to borrow funds required to pay the expenses. The trust may borrow the funds from any person,
including the trustee or its affiliates or, as described below, Chesapeake. The terms of such indebtedness, if funds were loaned by the entity serving as trustee or
Delaware trustee, must be similar to the terms which such entity would grant to a similarly situated, unaffiliated commercial customer, and such entity shall be entitled
to enforce its rights with respect to any such indebtedness as if it were not then serving as trustee or Delaware trustee. If the trust borrows funds, the trust unitholders
will not receive distributions until the borrowed funds are repaid (except in certain circumstances, where the trust borrows funds from Chesapeake). For information
regarding Chesapeake’s obligation to loan funds to the trust in certain limited circumstances, see “—Chesapeake Obligation to Fund Trust Expenses in Certain
Circumstances” on page 87.
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Each quarter, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the royalty interests
and hedging arrangements. The cash held by the trustee as a reserve against future liabilities must be invested in:
•
interest-bearing obligations of the U.S. government;
•
money market funds that invest only in U.S. government securities;
•
repurchase agreements secured by interest-bearing obligations of the U.S. government; or
•
bank certificates of deposit.
Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.
The trustee intends to withhold $1.0 million from the first distribution to establish an initial cash reserve available for trust expenses. If the trustee uses its cash
reserve (or any portion thereof) to pay or reimburse trust liabilities or expenses, no further distributions will be made to unitholders (except in respect of any previously
determined quarterly cash distribution amount) until the cash reserve is replenished. Additional cash reserves may also be established from time to time as determined
by the trustee to pay for future expenses of the trust. This cash reserve will be part of the trust estate and will bear interest at the same rate as other cash on hand in the
trust estate. Upon the dissolution of the trust, after payment of trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to
trust unitholders on a pro rata basis.
The trust may not acquire any asset except the royalty interests, the other assets described above under “—Assets of the Trust” on page 84, interests acquired in
connection with foreclosure under the Drilling Support Lien and cash and temporary cash investments, and it may not engage in any investment activity except
investing cash on hand. Chesapeake, acting as hedging manager for the trust, may cause the trust to restructure existing hedges in certain circumstances.
The trust agreement provides that the trustee will not make business decisions affecting the assets of the trust. However, the trustee may:
•
prosecute or defend, and settle, claims of or against the trust or its agents;
•
foreclose on the Drilling Support Lien if Chesapeake does not satisfy its drilling obligation on or before June 30, 2016, and contract with a third-party
operator to drill any remaining Development Wells, and transfer a portion of the trust’s assets in connection therewith;
•
retain professionals and other third parties to provide services to the trust;
•
charge for its services as trustee;
•
retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent
permitted by law);
•
lend funds at commercial rates to the trust to pay the trust’s expenses; and
•
seek reimbursement from the trust for its out-of-pocket expenses.
In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for willful misconduct, bad faith or
gross negligence, and certain taxes, fees and other charges based on fees, commissions or compensation received by the trustee in connection with the transactions
contemplated by the trust agreement. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted with willful misconduct,
bad faith or gross negligence in its selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the
administration of the trust, except in cases of willful misconduct, bad faith or gross negligence. The trustee will have a lien on the assets of the trust as security for this
indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust
Units—Liability of Trust Unitholders” on page 90. The trustee is obligated to ensure that all contractual liabilities of the trust are limited to the assets of the trust.
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Merger or Consolidation of Trust
The trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited
liability companies, or associations or unincorporated businesses if such transaction is agreed to by the trustee and approved by the vote of the holders of a majority of
the trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a
meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any
time that Chesapeake and its affiliates collectively own less than 10% of the outstanding trust units, however, the standard for approval will be the vote of a majority of
the trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present.
Trustee’s Power to Sell Trust Assets
The trustee may sell trust assets, including the royalty interests, under any of the following circumstances:
•
the sale is requested by Chesapeake, following the satisfaction of its drilling obligation, in accordance with the provisions of the trust agreement (see
“Description of the Royalty Interests—Additional Features of the Royalty Interests—Sale and Release of Underlying Properties” on page 81);
•
the sale is approved by the vote of holders representing a majority of the trust units and a majority of the common units (excluding common units
owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except
that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be the
vote of a majority of the trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum
is present; or
•
in connection with a foreclosure on the Drilling Support Lien.
Upon dissolution of the trust the trustee must sell the remaining royalty interests. No trust unitholder approval is required in this event. See “—Duration of the
Trust; Sale of Royalty Interests” on page 87.
The trustee will distribute the net proceeds from any sale of the royalty interests and other assets to the trust unitholders after payment or reasonable provision
for payment of the liabilities of the trust.
Permitted Amendments
The trustee may amend or supplement the trust agreement, the conveyances, the development agreement, the administrative services agreement, the hedging
arrangements, the registration rights agreement or the Drilling Support Lien, without the approval of the trust unitholders, to cure ambiguities, to correct or supplement
defective or inconsistent provisions, to grant any benefit to all trust unitholders, to add collateral to the Drilling Support Lien, to evidence or implement any changes
required by applicable law or to change the name of the trust, provided, however, that any such supplement or amendment does not adversely affect the interests of the
trust unitholders. Furthermore, the trustee, acting alone, may amend the administrative services agreement without the approval of trust unitholders if such amendment
would not increase the cost or expense of the trust or create an adverse economic impact on the trust unitholders. Finally, modifications of the hedging arrangements
entered into by the trust will not require the approval of the trust unitholders.
All other permitted amendments to the trust agreement and other agreements listed above may only be made by the vote of a majority of the trust units and a
majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders
at which a quorum is present; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding trust units, the standard for
approval will be the vote of a majority of the trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a
quorum is present. Abstentions and broker non-votes shall not be deemed to be a vote cast.
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Liabilities of the Trust; Fees and Expenses
The trust will be a party to oil and natural gas liquids hedging arrangements and could have payment obligations under such arrangements. Otherwise, the trust
does not conduct an active business and the trustee has little power to incur obligations. As a result, it is expected that the trust will only incur liabilities for routine
administrative expenses, such as legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at
the direction of the trustee or the Delaware trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and
transfer agent fees. The trust will also be responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the trustee’s and the
Delaware trustee’s compensation, and the fee payable to Chesapeake pursuant to the administrative services agreement, will be paid out of the trust’s assets. See “The
Trust” beginning on page 44, for more information on these costs.
Chesapeake Obligation to Fund Trust Expenses in Certain Circumstances
Chesapeake has agreed that, if at any time the trust’s cash on hand (including available cash reserves) is not sufficient to pay the trust’s ordinary course expenses
as they become due, Chesapeake will lend funds to the trust necessary to pay such expenses. Any funds loaned by Chesapeake pursuant to this commitment will be
limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other accrued
current liabilities arising in the ordinary course of the trust’s business, and may not be used to satisfy trust indebtedness for borrowed money. If Chesapeake lends funds
pursuant to this commitment, unless Chesapeake agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined
quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as
those which would be obtained in an arms’ length transaction between Chesapeake and an unaffiliated third party.
Duration of the Trust; Sale of Royalty Interests
The trust will not dissolve until the Termination Date, which is June 30, 2031, unless:
•
the trust sells all of the royalty interests;
•
cash available for distribution is less than $1.0 million for any four consecutive quarters;
•
the holders of a majority of the trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in
each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution; except that at any time
that Chesapeake and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be a majority of the trust
units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present; or
•
the trust is judicially dissolved.
In the case of any of the foregoing, the trustee would sell all of the trust’s assets, either by private sale or public auction, and distribute the net proceeds of the
sale to the trust unitholders after payment, or reasonable provision for payment, of all trust liabilities.
Dispute Resolution
To the fullest extent permitted by law, any dispute, controversy or claim that may arise between Chesapeake and the trustee relating to the trust will be submitted
to binding arbitration before a panel of three arbitrators.
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Tax Matters
Trust unitholders will be treated as partners of the trust for U.S. federal income tax purposes. The trust agreement contains tax provisions that generally allocate
the trust’s income, gain, loss, deduction and credit among the trust unitholders in accordance with their percentage interests in the trust. The trust agreement also sets
forth the tax accounting principles to be applied by the trust.
Miscellaneous
The trustee may consult with counsel (which may include counsel to Chesapeake), accountants, tax advisors, geologists and engineers and other parties the
trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the
opinion of the expert.
The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by the vote of a majority of the common units
(excluding common units owned by Chesapeake and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at
any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be the vote of a majority of the
trust units, including units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present. Abstentions and broker
non-votes shall not be deemed to be a vote cast. Any successor must be a bank or trust company meeting certain requirements including having combined capital,
surplus and undivided profits of at least $20 million, in the case of the Delaware trustee, and $100 million, in the case of the trustee.
The principal offices of the trust are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is (512) 236-6599.
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DESCRIPTION OF THE TRUST UNITS
Each trust unit is a unit of the beneficial interest in the trust and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder
has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust will have 45,750,000 trust units outstanding upon
completion of the offering, consisting of 34,312,500 common units and 11,437,500 subordinated units.
Common Units; Subordinated Units
The common units and subordinated units will have identical rights and privileges, except with respect to their voting rights and rights to receive distributions.
For a discussion of unitholders’ voting rights, see “—Voting Rights of Trust Unitholders” beginning on page 90.
The subordinated units will be entitled to receive pro rata distributions from the trust each quarter if and to the extent there is sufficient cash to provide a cash
distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is insufficient cash to fund such a distribution on all of the
common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the
extent possible, of up to the subordination threshold amount on all the common units, including the common units held by Chesapeake. For more information, see
“Target Distributions and Subordination and Incentive Thresholds” beginning on page 50.
The subordinated units will automatically convert into common units on a one-for-one basis at the end of the fourth full calendar quarter following Chesapeake’s
satisfaction of its drilling obligation to the trust with respect to the Development Wells.
Distributions; Income Computations
Cash distributions to trust unitholders will be made by the trust from its available funds for each calendar quarter. Royalty interest payments due to the trust with
respect to any calendar quarter will be based on actual production volumes attributable to the trust properties for the first two months of the quarter just ended as well as
the last month of the immediately preceding quarter (as measured at Chesapeake metering systems) and actual revenues received for such volumes. Chesapeake will
make the royalty interest payments to the trust within 35 days of the end of each calendar quarter. In addition, any payment due from or required to be made to the
counterparties under the trust’s hedging arrangements will be paid by the 40th day following the end of such calendar quarter. Taking into account the receipt and
disbursement of all such amounts, the trustee will determine for such calendar quarter the amount of funds available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the trust over the trust’s expenses for that quarter. Available funds will be reduced by any cash the trustee decides to hold
as a reserve against future liabilities.
The amount of available funds for distribution each quarter will be payable to the trust unitholders of record approximately 50 days following the end of such
calendar quarter or such later date as the trustee determines is required to comply with legal or stock exchange requirements. The trustee will distribute cash
approximately 60 days (or the next succeeding business day following such day if such day is not a business day) following such calendar quarter to each person who
was a trust unitholder of record on the quarterly record date, together with interest expected to be earned on the amount of such quarterly distribution from the date of
receipt thereof by the trustee to the payment date.
Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each quarter as belonging to the trust unitholders
of record on the quarterly record date that occurs in such quarter. Trust unitholders will recognize income and expenses for tax purposes in the quarter the trust receives
or pays those amounts, rather than in the quarter the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one quarter
that would not result in a tax deduction until a later quarter. The trustee could also make a payment in one quarter that would be amortized for tax purposes over several
months. See “U.S. Federal Income Tax Considerations” beginning on page 95.
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Transfer of Trust Units
Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a
service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the
owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by
any party except the record owner. A person who acquires a trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly
record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.
Tax Schedules and Periodic Reports
The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders a Schedule K-1
that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to
be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or
admitted to trading.
Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours the records of the trust and the trustee.
Liability of Trust Unitholders
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private
corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
Voting Rights of Trust Unitholders
The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust does not intend to hold annual
meetings of the trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the
trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in
such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to
be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units
outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned. Abstentions and broker non-votes
shall not be deemed to be a vote cast.
Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust
unitholders voting in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total outstanding trust units did not approve it.
Until such time as Chesapeake and its affiliates own less than 10% of the outstanding trust units, the affirmative vote of the holders of a majority of common
units (excluding common units owned by Chesapeake and its affiliates) and a majority of trust units voting in person or by proxy at a meeting of such holders at which a
quorum is present is required to:
•
dissolve the trust (except in accordance with its terms);
•
amend the trust agreement, the royalty conveyances, the administrative services agreement, the development agreement or the Drilling Support Lien
(except with respect to certain matters that do not adversely affect the right of trust unitholders in any material respect);
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•
merge or consolidate or convert the trust with or into another entity; or
•
approve the sale of all or any material part of the assets of the trust.
In addition, until such time as Chesapeake and its affiliates own less than 10% of the outstanding trust units, the vote of the holders of a majority of common
units (excluding common units owned by Chesapeake and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present is
required to remove the trustee and to appoint a successor trustee.
At any time when Chesapeake and its affiliates own less than 10% of the outstanding trust units, the vote of the holders of a majority of trust units, including
units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above.
Certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. The trustee must consent before all or any part
of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by Chesapeake in conjunction with its sale of Underlying
Properties.
Comparison of Trust Units and Common Stock
Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual
meetings of trust unitholders or for annual or other periodic re-election of the trustee.
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Unitholders should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.
Trust units
Common stock
Voting
The trust agreement provides voting rights to trust unitholders to
remove and replace (but not elect) the trustee and to approve or
disapprove major trust transactions.
Unless otherwise provided in the certificate of incorporation,
corporate statutes provide voting rights to stockholders of the
corporation to elect directors and to approve or disapprove
amendments to the certificate of incorporation and certain
major corporate transactions.
Income Tax
The trust is not subject to U.S. federal income tax; trust
unitholders are subject to income tax on their allocable share of
trust income, gain, loss and deduction.
Corporations are subject to U.S. federal income tax, and their
stockholders are taxed on dividends.
Distributions
All trust revenue is distributed to trust unitholders after payment
of trust expenses and additions, if any, to trust reserves.
Unless otherwise provided in the certificate of incorporation,
stockholders are entitled to receive dividends solely at the
discretion of the board of directors.
Business and Assets
The business of the trust is limited to specific assets with a finite
economic life.
Unless otherwise provided in the certificate of incorporation, a
corporation conducts an active business for an unlimited term
and can reinvest its earnings and raise additional capital to
expand.
Fiduciary Duties
To the extent provided in the trust agreement, the trustee has
limited its fiduciary duties in the trust agreement as permitted by
the Delaware Statutory Trust Act so that it will be liable to
unitholders only for willful misconduct, bad faith or gross
negligence.
Officers and directors have a fiduciary duty of loyalty to the
corporation and the stockholders and a duty to exercise due
care in the management and administration of a corporation’s
affairs.
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TRUST UNITS ELIGIBLE FOR FUTURE SALE
General
Prior to this offering, there has been no public market for the common units. Sales of substantial amounts of the common units in the open market, or the
perception that those sales could occur, could adversely affect prevailing market prices.
Upon completion of this offering, there will be 45,750,000 trust units outstanding and Chesapeake will own 11,437,500 common units and 11,437,500
subordinated units (assuming no exercise by the underwriters of their option to purchase additional common units). All of the subordinated units will convert into
common units at the end of the fourth full calendar quarter following satisfaction of Chesapeake’s drilling obligation. The sale of these units could have an adverse
impact on the price of our common units or on any trading market that may develop.
All of the 22,875,000 common units sold in this offering, or the 26,306,250 common units if the underwriters exercise their option to purchase additional
common units in full, will be freely tradable without restriction under the Securities Act. The 11,437,500 common trust units to be held by Chesapeake (8,006,250
common trust units if the underwriters exercise their option to purchase additional common units in full) following completion of the offering will be “restricted
securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an
exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting” beginning on page 113.
Chesapeake Lock-up Agreement
In connection with this offering, Chesapeake has agreed, for a period of 180 days after the date of this prospectus, that neither it nor its subsidiaries will offer,
sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units, without the prior written consent
of Morgan Stanley & Co. LLC and Raymond James & Associates, Inc. See “Underwriting” beginning on page 113 for a description of this lock-up agreement. Upon
the expiration of this lock-up agreement, all of the units held by Chesapeake will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to
volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.
Rule 144
The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any
common units owned by Chesapeake or any other affiliate of the trust may not be resold publicly except in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does
not exceed, during any three-month period, the greater of:
•
1.0% of the total number of the securities outstanding, or
•
the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current
public information about the trust. A person who is not deemed to have been an affiliate of the trust at any time during the three months preceding a sale, and who has
beneficially owned common units for at least six months (provided the trust is in compliance with the current public information requirement) or one year (regardless of
whether the trust is in compliance with the current public information requirement), would be entitled to sell unregistered common units under Rule 144 without regard
to the rule’s volume limitations, manner of sale provisions and notice requirements.
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Registration Rights Agreement
The trust intends to enter into a registration rights agreement for the benefit of Chesapeake and certain of its affiliates and transferees (each, a “holder”). In the
registration rights agreement, the trust will agree, for the benefit of each holder, to register the trust units held by such holder for resale under the Securities Act.
Specifically, the trust will agree:
•
subject to the lock-up restrictions described above and under “Underwriting,” beginning on page 113, to use its reasonable best efforts to file a
registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice
requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;
•
to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as
promptly as practicable after the filing thereof; and
•
to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration
statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such
registration statement or until all registrable trust units:
•
have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities”;
•
have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee
of the trust units; or
•
become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).
The holders will have the right to require the trust to file no more than five registration statements in aggregate.
In connection with the preparation and filing of any registration statement, Chesapeake will bear all costs and expenses incidental to any registration statement,
excluding certain internal expenses of the trust, which will be borne by the trust, and any underwriting discounts and commissions, which will be borne by the seller of
the trust units.
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U.S. FEDERAL INCOME TAX CONSIDERATIONS
This section is a discussion of the material tax considerations that may be relevant to prospective trust unitholders who are individual citizens or residents of the
United States and, unless otherwise noted in the following discussion, is the opinion of Bracewell & Giuliani LLP, counsel to Chesapeake and the trust, insofar as it
relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986,
as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and
current administrative rulings and court decisions, all of which are subject to change. Future changes in these authorities may cause the tax consequences to vary
substantially from the consequences described below.
The following discussion does not address all U.S. federal income tax matters affecting the trust or the trust unitholders. Moreover, the discussion focuses on
trust unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, taxpayers subject to the alternative minimum tax, individual
retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, the trust encourages each prospective trust
unitholder to consult his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of trust
units.
No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting the trust or prospective trust unitholders.
Instead, the trust will rely on opinions of counsel. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or
the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may
materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS, principally
legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust
unitholders. Furthermore, the tax treatment of the trust, or of an investment in the trust, may be significantly modified by future legislative or administrative changes or
court decisions. Any modifications may or may not be retroactively applied.
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of
Bracewell & Giuliani LLP and are based on the accuracy of the representations made by Chesapeake and the trust.
For the reasons described below, Bracewell & Giuliani LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues:
(a) the treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units (please read “—Tax Consequences of Trust Unit
Ownership—Treatment of Short Sales” on page 104); (b) whether the trust’s convention for allocating taxable income and losses is permitted by existing Treasury
Regulations (please read “—Disposition of Trust Units—Allocations Between Transferors and Transferees” on page 107); and (c) whether percentage depletion will be
available to a trust unitholder or the extent of the percentage depletion deduction available to any trust unitholder (please read “—Tax Consequences of Trust Unit
Ownership—Tax Treatment of the Perpetual Royalties” beginning on page 102).
As used herein, the term “trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:
•
an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes,
•
a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States,
a state thereof or the District of Columbia,
•
an estate the income of which is subject to U.S. federal income taxation regardless of its source, or
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•
a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal
income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.
The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit (other than an entity that is classified for U.S. federal income tax purposes as a
partnership or as a “disregarded entity”) that is not a trust unitholder.
If an entity that is classified for U.S. federal income tax purposes as a partnership is a beneficial owner of trust units, the tax treatment of a member of the entity
will depend upon the status of the member and the activities of the entity. The trust encourages any entity that is classified for U.S. federal income tax purposes as a
partnership and that is a beneficial owner of trust units, and the members of such an entity, to consult their own tax advisors about the U.S. federal income tax
considerations of purchasing, owning, and disposing of trust units.
Classification of the Trust as a Partnership
Although the trust is formed as a statutory trust under Delaware law, the trust’s classification for U.S. federal income tax purposes is based on its characteristics
rather than its form. Based on such characteristics, it is expected that, as described below, the trust will be treated for federal and applicable state income tax purposes as
a partnership and trust unitholders will be treated as partners in that partnership.
A partnership is not a taxable entity and incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account his
share of items of income, gain, loss, deduction and credit of the partnership in computing his federal income tax liability, regardless of whether cash distributions are
made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in
excess of the partner’s adjusted basis in his partnership interest as of the end of the taxable year in which the distribution is made.
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception,
referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for
every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, production and marketing
of oil, natural gas liquids and natural gas and interest income (other than from a financial business). Other types of qualifying income include gains from the sale of real
property and income from certain hedging transactions. The trust anticipates that substantially all of its gross income will be qualifying income. Based upon the factual
representations made by the trust and Chesapeake and a review of the applicable legal authorities, Bracewell & Giuliani LLP is of the opinion that at least 90% of the
trust’s gross income will constitute qualifying income.
No ruling has been or will be sought from the IRS and the IRS has made no determination as to the trust’s status for federal income tax purposes or whether the
trust’s operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, the trust will rely on the opinion of Bracewell & Giuliani
LLP on such matters. It is the opinion of Bracewell & Giuliani LLP that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and
court decisions and the representations described below, the trust will be classified as a partnership for federal income tax purposes.
In rendering its opinion, Bracewell & Giuliani LLP has relied on factual representations made by the trust and Chesapeake. The representations made by the trust
and Chesapeake upon which Bracewell & Giuliani LLP has relied are:
(a) The trust has not, and will not, elect to be treated as a corporation;
(b) The trust is, and will be organized and operated in accordance with (i) the trust agreement and (ii) the description thereof in this prospectus;
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(c) For each taxable year, more than 90% of the trust’s gross income will be income that Bracewell & Giuliani LLP has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the Internal Revenue Code; and
(d) Each hedging transaction that the trust treats as resulting in qualifying income will be appropriately identified as a hedging transaction pursuant to
applicable Treasury Regulations, and will be associated with oil, gas or products thereof that are held or will be held by the trust in activities that Bracewell & Giuliani
LLP has opined or will opine result in qualifying income.
The trust believes that these representations are true and expects that these representations will continue to be true in the future.
If the trust fails to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a
reasonable time after discovery (in which case the IRS may also require the trust to make adjustments with respect to the trust’s unitholders allocable share of trust
income, gain, loss or deduction or pay other amounts), the trust will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed
corporation, on the first day of the year in which the trust fails to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that
stock to the unitholders in liquidation of their interests in the trust. This deemed contribution and liquidation should be tax-free to the trust unitholders and the trust so
long as the trust’s liabilities do not exceed the tax basis of the trust’s assets. Thereafter, the trust would be treated as an association taxable as a corporation for federal
income tax purposes.
If the trust were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or
otherwise, the trust’s items of income, gain, loss and deduction would be reflected only on the trust’s tax return rather than being passed through to the trust unitholders,
and the trust’s net income would be taxed to the trust at corporate rates. In addition, any distribution made to a trust unitholder would be treated as either taxable
dividend income, to the extent of the trust’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the
extent of the trust unitholder’s tax basis in his trust units, or taxable capital gain, after the trust unitholder’s tax basis in his trust units is reduced to zero. Accordingly,
taxation as a corporation would result in a material reduction in a trust unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction
of the value of the trust units.
The discussion below is based on Bracewell & Giuliani LLP’s opinion that the trust will be classified as a partnership for U.S. federal income tax purposes.
Partner Status
Trust unitholders will be treated as partners of the trust for U.S. federal income tax purposes. Also, trust unitholders whose trust units are held in street name or
by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their trust units will be treated as
partners of the trust for U.S. federal income tax purposes.
A beneficial owner of trust units whose trust units have been transferred to a short seller to complete a short sale would appear, as a result, to lose his status as a
partner with respect to those trust units for U.S. federal income tax purposes. Please read “—Tax Consequences of Trust Unit Ownership—Treatment of Short Sales”
on page 104. Income, gain, deductions or losses would not appear to be reportable by a trust unitholder who is not a partner for federal income tax purposes, and any
cash distributions received by a trust unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income.
These unitholders are urged to consult their own tax advisors with respect to their tax considerations related to holding trust units. The references to “unitholders” in the
discussion that follows are to persons who are treated as partners in the trust for federal income tax purposes.
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Tax Classification of the PDP Royalty Interest and the Development Royalty Interest
For U.S. federal income tax purposes, the Perpetual PDP Royalty and the Perpetual Development Royalty will have the tax characteristics of mineral royalty
interests to the extent they are, at the time of their creation, reasonably expected to have an economic life that corresponds substantially to the economic life of the
mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for U.S.
federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.
In contrast, the Term PDP Royalty and the Term Development Royalty will have the tax characteristics of production payments governed by Section 636 of the
Internal Revenue Code to the extent they may not, at the time of their creation, be reasonably expected to extend in substantial amounts over the entire productive lives
of the mineral property or properties they burden. Payments out of production that are received in respect of a mineral interest that constitutes a production payment for
U.S. federal income tax purposes are treated under current law as consisting of a receipt of principal and interest on a nonrecourse debt obligation, with the interest
component being taxable as ordinary income.
In the event that a portion of a single royalty interest terminates by its terms prior to the point in time that the economically productive life of the burdened
mineral property is substantially exhausted and the remaining portion continues to burden the property until its economically productive life is substantially exhausted,
the federal income tax characteristics of the royalty interest are determined as if it comprised two separate interests, with the terminating portion being treated as a
production payment and the continuing portion being treated as a royalty interest.
Based on the reserve reports and representations made by Chesapeake regarding the expected economic life of the Underlying Properties and the expected
duration of the Term Royalties and the Perpetual Royalties, the Term PDP Royalty will and the Term Development Royalty should be treated as “production payments”
under Section 636 of the Internal Revenue Code, and thus as nonrecourse debt instruments of Chesapeake for U.S. federal income tax purposes. The Perpetual PDP
Royalty will and the Perpetual Development Royalty should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of
production from the mineral interests they burden.
The difference in certainty between the treatment of the Term PDP Royalty and the Perpetual PDP Royalty, on the one hand, and the Term Development
Royalty and the Perpetual Development Royalty, on the other hand, stems from the fact that while the Term PDP Royalty and Perpetual PDP Royalty are interests in the
Producing Wells (developed wells that have been drilled), the Term Development Royalty and Perpetual Development Royalty are interests in the Development Wells
(undeveloped wells that will be drilled in the future). The applicable laws are well developed, and directly applicable precedents exist, with regard to the tax treatment
of royalty interests in specified developed wells that have been drilled. Although such laws and precedents are applicable in analyzing the tax treatment of royalty
interests in proven reserves and undeveloped wells related thereto that will be drilled in the future, the law is less well developed in this area. As a result, the tax
treatment of the Term Development Royalty and the Perpetual Development Royalty are not entirely free from doubt. Therefore, the difference in certainty between the
treatment of the PDP Royalties and the Development Royalties set forth in the preceding paragraph and elsewhere in this prospectus reflects the difference in certainty
between developed and undeveloped wells.
Consistent with the foregoing, Chesapeake and the trust intend to treat the Perpetual Royalties as mineral royalty interests for U.S. federal income tax purposes.
In addition, Chesapeake and the trust intend to treat the Term Royalties as debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations
applicable to contingent payment debt instruments (the “CPDI regulations”), and the trust will agree to be bound by Chesapeake’s application of the CPDI regulations,
including Chesapeake’s determination of the rate at which interest will be deemed to accrue on such interests. No assurance can be given that the IRS will not assert that
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such interests should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in
trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below. Please read “—Tax
Consequences of Trust Unit Ownership—Tax Treatment of the Term Royalties” beginning on page 100, and “—Tax Consequences of Trust Unit Ownership—Tax
Treatment of the Perpetual Royalties” beginning on page 102.
Tax Consequences of Trust Unit Ownership
Flow-Through of Taxable Income. As a partnership for U.S. federal income tax purposes, the trust will not be a taxable entity required to pay any federal income
tax. Instead, each trust unitholder will be required to report on his income tax return his allocable share of the trust’s income, gains, losses, deductions and credits
without regard to whether the trust makes cash distributions to him. Consequently, the trust may allocate taxable income to a trust unitholder even if he has not received
a cash distribution.
Accounting Method and Taxable Year. The trust will use the year ending December 31 as its taxable year and the accrual method of accounting for U.S. federal
income tax purposes. Each trust unitholder will be required to include in income his share of the trust’s income, gain, loss, deduction and credit for the trust’s taxable
year ending within or with his taxable year. In addition, a trust unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of
his trust units following the close of the trust’s taxable year but before the close of his taxable year must include his share of the trust’s income, gain, loss, deduction
and credit in his taxable income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than 12 months of
the trust’s income, gain, loss, deduction and credit. Please read “—Disposition of Trust Units—Allocations Between Transferors and Transferees” on page 107.
A trust unitholder’s initial tax basis for his trust units will be the amount he paid for the trust units. That basis will be increased by his share of the trust’s income
and gain and decreased, but not below zero, by distributions from the trust, by the trust unitholder’s share of the trust’s losses, if any, by depletion deductions taken by
him to the extent such deductions do not exceed his proportionate allocated share of the adjusted tax basis of the Perpetual Royalties, and by his share of the trust’s
expenditures that are not deductible in computing taxable income and are not required to be capitalized. Please read “—Disposition of Trust Units—Recognition of
Gain or Loss” beginning on page 106.
Allocation of Income, Gain, Loss, Deduction and Credit. In general, if the trust has a net profit, the trust’s items of income, gain, loss, deduction and credit will
be allocated among the trust unitholders in accordance with their percentage interests in the trust. At any time that distributions are made to the common units in excess
of distributions to the subordinated trust units, or Chesapeake receives incentive distributions, gross income will be allocated to the recipients to the extent of these
distributions. If the trust has a net loss, that loss will be allocated first to the subordinated trust units to the extent of their positive capital accounts and thereafter to the
trust unitholders in accordance with their percentage interests in the trust.
Specified items of the trust’s income, gain, loss, deduction and credit will be allocated under Section 704(c) of the Internal Revenue Code to account for any
difference between the tax basis and fair market value of any property treated as having been contributed to the trust by Chesapeake or certain of its affiliates that exists
at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the
difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax
basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” The effect of these 704(c) Allocations to a unitholder purchasing trust units
from the trust in this offering will be essentially the same as if the tax bases of the trust’s assets were equal to their fair market value at the time of this offering. Finally,
although the trust does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of the
trust’s income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
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An allocation of items of the trust’s income, gain, loss, deduction or credit, other than an allocation required by Section 704(c) of the Internal Revenue Code to
eliminate the Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a unitholder’s share of an item of income, gain,
loss, deduction or credit only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his
interest in the trust, which will be determined by taking into account all the facts and circumstances, including:
•
his relative contributions to the trust;
•
the interests of all the unitholders in profits and losses;
•
the interest of all the unitholders in cash flow; and
•
the rights of all the unitholders to distributions of capital upon liquidation.
Bracewell & Giuliani LLP is of the opinion that, with the exception of the issues described in “Disposition of Trust Units—Allocations Between Transferors and
Transferees” on page 107, allocations under the trust agreement will be given effect for U.S. federal income tax purposes in determining a unitholder’s share of an item
of income, gain, loss, deduction or credit.
Treatment of Trust Distributions. Distributions by the trust to a trust unitholder generally will not be taxable to the trust unitholder for U.S. federal income tax
purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his trust units immediately before the distribution. The trust’s cash
distributions in excess of a unitholder’s tax basis (if any) generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with
the rules described under “—Disposition of Trust Units” beginning on page 106.
Ratio of Taxable Income to Distributions. The trust estimates that a purchaser of trust units in this offering who owns those trust units from the date of closing of
this offering through the record date for distributions for the period ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable
income for that period that will be approximately 55% of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other
things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on
current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these
estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any
differences could be material and could materially affect the value of the trust units.
Tax Treatment of the Term Royalties. Under the CPDI regulations, the trust generally will be required to accrue income on the Term Royalties which are treated
as production payments, and therefore as nonrecourse debt obligations of Chesapeake for U.S. federal income tax purposes, in the amounts described below.
The CPDI regulations provide that the trust must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period
prior to and including the maturity date of the debt instrument that equals:
•
the product of (i) the adjusted issue price (as defined below) of the debt instrument as of the beginning of the accrual period; and (ii) the comparable
yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;
•
divided by the number of days in the accrual period; and
•
multiplied by the number of days during the accrual period that the trust held the debt instrument.
The “issue price” of the debt instrument represented by each production payment held by the trust is the portion of the first price at which a substantial amount of
the trust units is sold to the public, excluding sales to
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bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers, that is allocable to the production
payment based on the relative fair market value of the production payment to the other assets of the trust. The “adjusted issue price” of such a debt instrument is its
issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by
the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid). The term
“comparable yield” means the annual yield Chesapeake would be expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments
but with terms and conditions otherwise comparable to those of the debt instrument represented by the production payment.
Chesapeake will determine the comparable yield for each debt instrument held by the trust and will provide this information to the trust. In addition, the CPDI
regulations require that Chesapeake provide to the trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the
projected amounts of payments, which are referred to as projected payments, on the Term Royalties treated as debt instruments held by the trust. These payments set
forth on the schedule must produce a total return on such debt instruments equal to their comparable yield. Amounts treated as interest under the CPDI regulations are
treated as original issue discount for all purposes of the Internal Revenue Code.
As required by the CPDI regulations, for U.S. federal income tax purposes, the trust must use the comparable yield and the schedule of projected payments as
described above in determining the trust’s interest accruals, and the adjustments thereto described below, in respect of the debt instruments held by the trust.
Chesapeake’s determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations.
If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the trust would be different from those reported by the
trust or included on previously filed tax returns by the trust unitholders.
The comparable yield and the schedule of projected payments are not determined for any purpose other than for the determination for U.S. federal income tax
purposes of the trust’s interest accruals and adjustments thereof in respect of the debt instruments held by the trust and do not constitute a projection or representation
regarding the actual amounts payable to the trust.
For U.S. federal income tax purposes, the trust is required under the CPDI regulations to use the comparable yield and the projected payment schedule
established by Chesapeake in determining interest accruals and adjustments in respect of the production payments, unless the trust timely discloses and justifies the use
of a different comparable yield and projected payment schedule to the IRS. Pursuant to the terms of the conveyance, Chesapeake and the trust have agreed (in the
absence of an administrative determination or judicial ruling to the contrary) to be bound by Chesapeake’s determination of the comparable yield and projected payment
schedule.
If, during any taxable year, the trust receives actual payments with respect to a debt instrument held by the trust that in the aggregate exceed the total amount of
projected payments for that taxable year, the trust will incur a “net positive adjustment” under the CPDI regulations equal to the amount of such excess. The trust will
treat a “net positive adjustment” as additional interest income for such taxable year.
If the trust receives in a taxable year actual payments with respect to a debt instrument held by the trust that in the aggregate are less than the amount of
projected payments for that taxable year, the trust will incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This
adjustment will (a) reduce the trust’s interest income on the debt instrument held by the trust for that taxable year, and (b) to the extent of any excess after the
application of (a) give rise to an ordinary loss to the extent of the trust’s interest income on such debt instrument during prior taxable years, reduced to the extent such
interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative
adjustment to offset future interest income in respect of that debt instrument held
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by the trust. If either of the Term Royalties is not treated as a production payment (and not otherwise as a debt instrument) for U.S. federal income tax purposes, the
trust intends to take the position that its basis in the Term Royalty is recouped in proportion to the production from the Term Royalty.
Neither the trust nor the trust unitholders are entitled to claim depletion deductions with respect to the Term Royalties.
Tax Treatment of the Perpetual Royalties. The payments received by the trust in respect of the Perpetual Royalties treated as mineral royalty interests for U.S.
federal income tax purposes will be treated as ordinary income, and trust unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise
allowable) percentage depletion with respect to such income. Although the Internal Revenue Code requires each trust unitholder to compute his own depletion
allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interest for depletion and other purposes, the trust intends to furnish each
of the trust unitholders with information relating to this computation for U.S. federal income tax purposes. Each trust unitholder, however, remains responsible for
calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the Perpetual Royalties for depletion and other purposes.
Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in Section 613A(c)
of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, oil and natural gas, or
derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal
production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction
with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion
allowance. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily
production of domestic oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil, natural gas liquids and
natural gas production, with 6,000 cubic feet of domestic oil, natural gas liquids and natural gas production regarded as equivalent to one barrel of crude oil. The
1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective
production by such persons during the period in question.
In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from
all sources for the year, computed without the depletion allowance, the deduction for domestic production activities, net operating loss carrybacks, or capital loss
carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion
deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting
from the 65% net income limitation is unlimited.
In addition to the limitations on percentage depletion discussed above, President Obama’s budget proposal for the fiscal year 2012 proposes to eliminate certain
tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for
percentage depletion with respect to wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever
be enacted and, if so, when any such proposal would become effective.
Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost
depletion deductions are calculated by (i) dividing the trust unitholder’s allocated share of the adjusted tax basis in the underlying mineral property by the number of
mineral units (barrels of oil and thousand cubic feet of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of
mineral units sold within the taxable year. The total amount of
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deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.
The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the
availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder
and not by the trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion
deductions to the trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether
percentage depletion would be available to him.
Tax Treatment Upon Sale of the Perpetual Royalties at Termination Date. The sale of the Perpetual Royalties by the trust at or shortly after the Termination Date
will generally give rise to long-term capital gain or loss to the trust unitholders for U.S. federal income tax purposes, except that any gain will be taxed at ordinary
income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Perpetual Royalties. Each trust unitholder will be responsible
for calculating his gain or loss based on the difference between his pro-rata share of the amount realized on the sale by the trust and his adjusted basis in the Perpetual
Royalties, and if a gain is realized, the portion thereof taxable as ordinary income by reason of depletion deductions previously claimed by such trust unitholder.
However, the trust intends to furnish each of the trust unitholders with information relating to this calculation for U.S. federal income tax purposes in connection with
the final partnership tax return for the trust.
Tax Treatment of Hedging Income. Income or loss realized with respect to hedging arrangements entered into by the trust will give rise to ordinary income or
loss to the trust unitholders for U.S. federal income tax purposes. Trust unitholders will not be entitled to depletion deductions with respect to any hedging income.
Limitations on Deductibility of Losses. It is not anticipated that the trust will generate losses. Nevertheless, should losses result, trust unitholders must consult
their own tax advisors as to the applicability to them of loss limitation rules that could operate to limit the deductibility to a trust unitholder of his share of the trust’s
losses such as the basis limitation, the “at risk” rules and the passive loss rules. Special passive loss limitation rules apply with respect to publicly-traded partnerships.
Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that
taxpayer’s “net investment income.” Investment interest expense includes:
•
interest on indebtedness properly allocable to property held for investment;
•
the trust’s interest expense attributed to portfolio income; and
•
the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
The computation of a trust unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to
purchase or carry a trust unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains
attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly
traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the trust unitholder’s
share of the trust’s portfolio income will be treated as investment income.
Entity-Level Withholdings. If the trust is required or elects under applicable law to pay any federal, state, local or foreign income tax on behalf of any trust
unitholder or any former trust unitholder, the trust is authorized
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to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the trust unitholder on whose behalf the payment was made. If the
payment is made on behalf of a person whose identity cannot be determined, the trust is authorized to treat the payment as a distribution to all current trust unitholders.
The trust is authorized to amend its trust agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of trust units. Payments by the trust as
described above could give rise to an overpayment of tax on behalf of an individual trust unitholder in which event the trust unitholder would be required to file a claim
in order to obtain a credit or refund.
Treatment of Short Sales. A trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having
disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may
recognize gain or loss from the disposition. As a result, during this period:
•
any of the trust’s income, gain, loss, deduction or credit with respect to those trust units would not be reportable by the trust unitholder;
•
any cash distributions received by the trust unitholder as to those trust units would be fully taxable; and
•
all of these distributions would appear to be ordinary income.
Bracewell & Giuliani LLP has not rendered an opinion regarding the tax treatment of a trust unitholder whose trust units are loaned to a short seller to cover a
short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged
to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their trust units. The IRS has previously announced that it
is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Trust Units—Recognition of Gain or Loss”
beginning on page 106.
Alternative Minimum Tax. Each trust unitholder will be required to take into account his distributive share of any items of the trust’s income, gain, loss,
deduction or credit for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative
minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective trust unitholders are urged to
consult with their tax advisors as to the impact of an investment in trust units on their liability for the alternative minimum tax.
Tax Rates. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal
U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%.
However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income
and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by
individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a trust unitholder’s
allocable share of the trust’s income and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of
(i) the trust unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s adjusted gross income exceeds $250,000 (if the trust
unitholder is married and filing jointly or a surviving spouse), $125,000 (if the trust unitholder is married and filing separately) or $200,000 (in any other case). In the
case of an estate or trust, the tax will be imposed on the lesser of (a) the undistributed net investment income of the estate or trust, or (b) the excess of the adjusted gross
income of the estate or trust over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
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Section 754 Election. The trust will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of
the IRS. The election will generally permit the trust to adjust a subsequent trust unit purchaser’s tax basis in the trust’s assets (“inside basis”) under Section 743(b) of
the Internal Revenue Code to reflect his purchase price of trust units acquired from another trust unitholder. The Section 743(b) adjustment belongs to the purchaser and
not to other trust unitholders. For purposes of this discussion, a trust unitholder’s inside basis in the trust’s assets will be considered to have two components: (a) his
share of tax basis in the trust’s assets (“common basis”) and (b) his Section 743(b) adjustment to that basis.
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of the trust’s assets
immediately prior to the transfer. In such a case, as a result of the election, the transferee would have a higher tax basis in his share of the trust’s assets for purposes of
calculating, among other items, cost depletion deductions on the Perpetual Royalties, and his share of any gain on a sale of the trust’s assets would be less. Conversely,
a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those trust units’ share of the aggregate tax basis of the trust’s assets
immediately prior to the transfer. Thus, the fair market value of the trust units may be affected either favorably or unfavorably by the election. A basis adjustment is
required regardless of whether a Section 754 election is made in the case of a transfer of an interest in the trust if it has a substantial built-in loss immediately after the
transfer. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of the trust’s assets and other
matters. For example, the allocation of the Section 743(b) adjustment among the trust’s assets must be made in accordance with the Internal Revenue Code. The trust
cannot assure unitholders that the determinations it makes will not be successfully challenged by the IRS and that the deductions resulting from them will not be
reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in the trust’s opinion, the expense of compliance exceed
the benefit of the election, the trust may seek permission from the IRS to revoke its Section 754 election. If permission is granted, a subsequent purchaser of trust units
may be allocated more income than he would have been allocated had the election not been revoked.
Initial Tax Basis and Amortization. The initial tax basis of the portion of the PDP Royalty Interest treated as a royalty interest in minerals and the portion treated
as a production payment, and the initial basis of the portion of the Development Royalty Interest treated as a royalty interest in minerals and the portion treated as a
production payment will be effectively equal on a per-unit basis to the portion of the unit price allocated to each based on each such portion’s relative fair market value.
The costs incurred in selling the trust units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon the trust’s
termination. There are uncertainties regarding the classification of costs as organizational expenses, which may be amortized by the trust, and as syndication expenses,
which may not be amortized by the trust. The underwriting discounts and commissions the trust incurs will be treated as syndication expenses.
Valuation and Tax Basis of the Trust’s Properties. The U.S. federal income tax consequences of the ownership and disposition of trust units will depend in part
on the trust’s estimates of the relative fair market values, and the initial tax bases, of the trust’s assets. Although the trust may from time to time consult with
professional appraisers regarding valuation matters, the trust will make many of the relative fair market value estimates itself. These estimates and determinations of
basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character
and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with respect to those adjustments.
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Disposition of Trust Units
Recognition of Gain or Loss. Gain or loss will be recognized on a sale of trust units equal to the difference between the amount realized and the trust unitholder’s
tax basis for the trust units sold. A trust unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received. The
amount realized should be reduced by the unused net negative adjustments attributable to the trust units disposed of as described above under “—Tax Consequences of
Trust Unit Ownership—Tax Treatment of the Term Royalties” beginning on page 100. A trust unitholder’s adjusted tax basis in his trust units will be equal to the trust
unitholder’s original purchase price for the trust units, increased by income and decreased by losses or deductions previously allocated to the trust unitholder and by
distributions to the trust unitholder and depletion deductions claimed by the trust unitholder.
Prior distributions from the trust in excess of cumulative net taxable income for a trust unit that decreased a unitholder’s tax basis in that trust unit will, in effect,
become taxable income if the trust unit is sold at a price greater than the trust unitholder’s tax basis in that trust unit, even if the price received is less than his original
cost.
Except as noted below, gain or loss recognized by a trust unitholder, other than a “dealer” in trust units, on the sale or exchange of a trust unit will generally be
taxable as capital gain or loss. Capital gain recognized by an individual on the sale of trust units held for more than 12 months will generally be taxed at a maximum
U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a
portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue
Code to the extent attributable to assets giving rise to “unrealized receivables” the trust owns. The term “unrealized receivables” includes potential recapture items,
including depletion recapture. Ordinary income attributable to unrealized receivables such as depletion recapture may exceed net taxable gain realized upon the sale of a
trust unit and may be recognized even if there is a net taxable loss realized on the sale of a trust unit. Thus, a trust unitholder may recognize both ordinary income and a
capital loss upon a sale of trust units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only
be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax
basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an
“equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s
tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations
under Section 1223 of the Internal Revenue Code allow a selling trust unitholder who can identify trust units transferred with an ascertainable holding period to elect to
use the actual holding period of the trust units transferred. Thus, according to the ruling discussed above, a trust unitholder will be unable to select high or low basis
trust units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific trust units sold for purposes of
determining the holding period of trust units transferred. A trust unitholder electing to use the actual holding period of trust units transferred must consistently use that
identification method for all subsequent sales or exchanges of trust units. A trust unitholder considering the purchase of additional trust units or a sale of trust units
purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a
taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if
the taxpayer or related persons enter(s) into:
•
a short sale;
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•
an offsetting notional principal contract; or
•
a futures or forward contract with respect to the partnership interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the
partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially
identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees. In general, the trust’s taxable income and losses will be determined and allocated on a quarterly basis and
apportioned among the trust unitholders in proportion to the number of trust units owned of record by each of them as of the opening of the applicable exchange on
which the trust units are then traded on the quarterly record date occurring in such quarter, which is referred to in this prospectus as the “Allocation Date.”
Although simplifying conventions are contemplated by the Internal Revenue Code, the use of this method may not be permitted under existing Treasury
Regulations. Accordingly, Bracewell & Giuliani LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and
transferee trust unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the trust unitholder’s interest, the
trust’s taxable income or losses might be reallocated among the trust unitholders. The trust is authorized to revise its method of allocation between transferor and
transferee trust unitholders, as well as trust unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
Notification Requirements. A trust unitholder who sells any of his trust units is generally required to notify the trust in writing of that sale within 30 days after
the sale (or, if earlier, January 15 of the year following the sale). A purchaser of trust units who purchases trust units from another trust unitholder is also generally
required to notify the trust in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, the trust is required to notify the IRS of that
transaction and to furnish specified information to the transferor and transferee. Failure to notify the trust of a purchase may, in some cases, lead to the imposition of
penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who affects the sale or exchange
through a broker who will satisfy such requirements.
Constructive Termination. The trust will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate,
constitute 50% or more of the total interests in the trust’s capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is
reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of the trust’s taxable year for all trust unitholders. In
the case of a trust unitholder reporting on a taxable year other than a calendar year, the closing of the trust’s taxable year may result in more than 12 months of the
trust’s taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31
will result in the trust filing two tax returns (and trust unitholders may receive two Schedule K-1’s) for one fiscal year and the cost of the preparation of these returns
will be borne by all trust unitholders. The trust would be required to make new tax elections after a termination, including a new election under Section 754 of the
Internal Revenue Code. A termination could also result in penalties if the trust was unable to determine that the termination had occurred. Moreover, a termination
might either accelerate the application of, or subject the trust to, any tax legislation enacted before the termination.
Tax-Exempt Organizations and Certain Other Investors
Ownership of trust units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises
issues unique to those investors and, as described below,
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may have substantially adverse tax consequences to them. If a potential investor is a tax-exempt entity or a non-U.S. person, then it should consult a tax advisor before
investing in the trust units.
Tax-Exempt Organizations. Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement
plans are subject to U.S. federal income tax on unrelated business taxable income. Because all of the income of the trust is expected to be royalty income, interest
income, hedging income and gain from the sale of real property, none of which is unrelated business taxable income, any such organization exempt from U.S. federal
income tax is not expected to be taxable on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are
debt-financed property within the meaning of Section 514(b) of the Internal Revenue Code. In general, trust property would be debt-financed if the trust incurs debt to
acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit
would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or
maintained if the trust unit had not been acquired.
Non-U.S. Persons. The trust (or the appropriate intermediary if units are held in “Street Name”) will be required to withhold (at a 30% rate or lower applicable
treaty rate) on gross interest and royalty income paid to non-U.S. trust unitholders. The trustee is authorized to adopt such conventions related to withholding as it
deems appropriate for the proper administration of the trust. Any convention adopted by the trustee may not be consistent with the Internal Revenue Code or the
Treasury Regulations. Neither the trust nor Bracewell & Giuliani LLP can assure trust unitholders that the IRS will not successfully challenge any withholding
convention adopted by the trustee.
Moreover, each of the PDP Royalty Interest and the Development Royalty Interest will be treated as a “United States real property interest” for U.S. federal
income tax purposes. However, as long as the trust units are regularly traded on an established securities market, gain realized by a non-U.S. trust unitholder on a sale of
trust units will be subject to U.S. federal income tax only if:
•
the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an
applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder;
•
the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions
are met; or
•
the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the
trust units.
Gain realized by a non-U.S. trust unitholder upon the sale or other taxable disposition by the trust of any PDP Royalty Interest or Development Royalty Interest
would be subject to federal income tax, and distributions to the non-U.S. trust unitholder would be subject to withholding of U.S. tax (currently at the rate of 35%) to
the extent distributions are attributable to such gains.
Administrative Matters
Trust Information Returns and Audit Procedures. The trust intends to furnish to each trust unitholder, within 90 days after the close of each calendar year,
specific tax information, including a Schedule K-1, which describes his share of the trust’s income, gain, loss and deduction for the trust’s preceding taxable year. In
preparing this information, which will not be reviewed by counsel, the trust will take various accounting and reporting positions, some of which have been mentioned
earlier, to determine each trust unitholder’s share of income, gain, loss and deduction. The trust cannot assure unitholders that those positions will yield a result that
conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither the trust nor Bracewell &
Giuliani LLP can assure prospective trust unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the
IRS could negatively affect the value of the units.
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The IRS may audit the trust’s U.S. federal income tax information returns. Adjustments resulting from an IRS audit may require each trust unitholder to adjust a
prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a trust unitholder’s return could result in adjustments not related to the trust’s
returns as well as those related to the trust’s returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax
settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate
proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The trust agreement
names an affiliate of Chesapeake as the trust’s Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on behalf of the trust and the trust unitholders. In addition, the Tax Matters Partner can extend
the statute of limitations for assessment of tax deficiencies against trust unitholders for items in the trust’s returns. The Tax Matters Partner may bind a trust unitholder
with less than a 1% profits interest in the trust to a settlement with the IRS unless that trust unitholder elects, by filing a statement with the IRS, not to give that
authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the trust unitholders are bound, of a final partnership
administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any trust unitholder having at least a 1%
interest in profits or by any group of trust unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go
forward, and each trust unitholder with an interest in the outcome may participate.
A trust unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the
treatment of the item on the trust’s return. Intentional or negligent disregard of this consistency requirement may subject a trust unitholder to substantial penalties.
Nominee Reporting. Persons who hold an interest in the trust as a nominee for another person are required to furnish to the trust:
(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;
(b) whether the beneficial owner is:
(i) a person that is not a United States person;
(ii) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
(iii) a tax-exempt entity;
(c) the amount and description of units held, acquired or transferred for the beneficial owner; and
(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the
amount of net proceeds from sales.
Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on
units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal
Revenue Code for failure to report that information to the trust. The nominee is required to supply the beneficial owner of the trust units with the information furnished
to the trust.
Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified
causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the
Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and
that the taxpayer acted in good faith regarding that portion.
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For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax
required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable
to a position adopted on the return:
(a) for which there is, or was, “substantial authority”; or
(b) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the distributive shares of trust unitholders might result in that kind of an “understatement” of income
for which no “substantial authority” exists, the trust must disclose the pertinent facts on its return. In addition, the trust will make a reasonable effort to furnish sufficient
information for trust unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit trust unitholders to avoid liability
for this penalty. More stringent rules apply to “tax shelters,” which the trust does not believe includes it, or any of the trust’s investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the
amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such
return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined
under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the
lesser of $5 million or 10% of the taxpayer’s gross receipts.
No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most
corporations). The penalty is increased to 40% in the event of a gross valuation misstatement. The trust does not anticipate making any valuation misstatements.
Reportable Transactions. If the trust were to engage in a “reportable transaction,” the trust (and possibly the unitholders) would be required to make a detailed
disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax
avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and
trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. The trust’s participation in a reportable transaction could
increase the likelihood that the trust’s U.S. federal income tax information return (and possibly the unitholders’ tax return) would be audited by the IRS. Please read
“—Trust Information Returns and Audit Procedures” beginning on page 108.
Moreover, if the trust were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, unitholders may
be subject to the following provisions of the American Jobs Creation Act of 2004:
•
accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at
“—Accuracy-Related Penalties” beginning on page 109;
•
for those persons otherwise entitled to deduct interest on federal tax deficiencies, non-deductibility of interest on any resulting tax liability; and
•
in the case of a listed transaction, an extended statute of limitations.
The trust does not expect to engage in any “reportable transactions.”
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STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust
unitholders. Bracewell & Giuliani LLP has not rendered an opinion on the state tax consequences of an investment in the trust. Trust unitholders are urged to consult
their own legal and tax advisors with respect to these matters.
Prospective investors should consider state and local income tax consequences of an investment in the trust units. The trust will own royalty interests burdening
specified oil and natural gas properties located in Washita County, Oklahoma. If the trust is treated as a partnership for federal income tax purposes, it should also be
treated as a partnership for Oklahoma income tax purposes. Trust unitholders generally will be subject to Oklahoma income tax on trust royalty income allocable to the
unitholders; accordingly, trust unitholders generally will be required to file Oklahoma state income tax returns and pay taxes in Oklahoma, and may be subject to
penalties for failure to comply with such requirements. The current highest marginal rates for the payment of Oklahoma state income taxes are 5.5% for individuals,
trusts and estates, and 6% for corporations. Generally, Oklahoma taxpayers are entitled to a depletion allowance on oil and natural gas income for state income tax
purposes equal to the greater of cost depletion or percentage depletion, with the percentage depletion allowance for most taxpayers being 22%, but not in excess of 50%
of the net income from the property (without regard to depletion); however, each trust unitholder should consult their own legal and tax advisors to determine the
Oklahoma depletion allowance specifically applicable to such unitholder. Although payments to out-of-state interest owners, including beneficial owners such as trust
unitholders, in respect of Oklahoma oil and natural gas income generally are subject to withholding for Oklahoma income tax purposes at the rate of 5%, an exception
exists for publicly traded partnerships that furnish detailed information concerning beneficial owners to the Oklahoma Tax Commission. The trust plans to furnish such
information and comply with those Oklahoma Tax Commission requirements as necessary to avoid withholding for Oklahoma state income tax purposes. Special
withholding rules may apply to non-U.S. trust unitholders. Although Oklahoma municipalities are statutorily authorized to assess income taxes, no municipality has
enacted such a tax. If an Oklahoma municipality were to enact an income tax, the tax could not be levied on nonresidents of the municipality.
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ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended (referred to as “ERISA”), regulates qualified pension plans, profit-sharing plans, stock
bonus plans, simplified employee pension plans, Keogh plans, tax deferred annuities or IRAs established or maintained by an employer or employee organization, and
other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code
provides similar requirements and standards which are applicable to qualified plans, which include certain of the plans described above, and to individual retirement
accounts, whether or not subject to ERISA.
A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before
authorizing an investment in trust units. Among other things, a fiduciary should consider:
•
whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;
•
whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and
•
whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.
A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of
ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are
plan assets in the transaction. The Department of Labor has published regulations concerning whether or not a plan’s assets would be deemed to include an interest in
the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal
Revenue Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly
offered security. Chesapeake expects that, at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will
need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal
Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit
plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust
units.
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UNDERWRITING
Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom
Morgan Stanley & Co. LLC and Raymond James & Associates, Inc. are acting as representatives, have severally agreed to purchase the number of common units
indicated below:
Number of
Common
Units
Underwriter
Morgan Stanley & Co. LLC
Raymond James & Associates, Inc.
Deutsche Bank Securities Inc.
Goldman, Sachs & Co.
Wells Fargo Securities, LLC
Barclays Capital Inc.
BNP Paribas Securities Corp.
Citigroup Global Markets Inc.
Credit Agricole Securities (USA) Inc.
Credit Suisse Securities (USA) LLC
Mitsubishi UFJ Securities (USA), Inc.
Mizuho Securities USA Inc.
Natixis Securities Americas LLC
RBS Securities Inc.
Scotia Capital (USA) Inc.
UBS Securities LLC
Comerica Securities, Inc.
Banco Bilbao Vizcaya Argentaria, S.A.
DnB NOR Markets, Inc.
Macquarie Capital (USA) Inc.
Nomura Securities International, Inc.
PNC Capital Markets LLC
SMBC Nikko Capital Markets Limited
SunTrust Robinson Humphrey, Inc.
TD Securities (USA) LLC
Total
22,875,000
The underwriting agreement provides that the obligations of the underwriters to pay for and accept delivery of the common units offered by this prospectus are
subject to the satisfaction of customary conditions, including the approval of certain legal matters by their counsel; the accuracy of representations and warranties made
by the trust and Chesapeake to the underwriters; there having been no material adverse change in financial markets or in the condition (financial or otherwise), business,
prospects, management or results of operations of the trust, the underlying properties or Chesapeake; and other similar conditions. The underwriters are obligated to
take and pay for all of the common units offered by this prospectus, if any are taken. However, the underwriters are not required to take or pay for the common units
covered by the underwriters’ option to purchase additional common units described below.
The underwriters initially propose to offer part of the common units directly to the public at the public offering price listed on the cover page of this prospectus
and part to certain dealers at a price that represents a concession not in excess of $
per common unit under the public offering price. After the initial offering of the
common units, the offering price and other selling terms may from time to time be varied by the representatives.
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The trust has granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an aggregate of 3,431,250
additional common units at the public offering price listed on the cover page of this prospectus, less underwriting discounts and commissions. To the extent the option is
exercised, each underwriter will become obligated, subject to certain conditions, to purchase approximately the same percentage of the additional common units as the
number listed next to the underwriter’s name in the preceding table bears to the total number of common units listed next to the names of all underwriters in the
preceding table.
If the underwriters do not exercise their option to purchase additional common units, the trust will deliver 3,431,250 common units to a subsidiary of
Chesapeake upon the option’s expiration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units
purchased by the underwriters pursuant to such exercise will be sold to the public and the remainder, if any, will be delivered to a subsidiary of Chesapeake.
Accordingly, the exercise of the underwriters’ option to purchase additional common units will not affect the total number of common units outstanding.
The underwriters have informed the trust that they do not intend sales to discretionary accounts to exceed 5% of the total number of common units offered by
them.
The common units have been approved for listing on the New York Stock Exchange under the symbol “CHKR.” In connection with the listing of the trust units
on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.
Chesapeake has agreed that, subject to specified exceptions, without the prior written consent of Morgan Stanley & Co. LLC and Raymond James & Associates,
Inc. on behalf of the underwriters, Chesapeake and its subsidiaries will not, during the period ending 180 days after the date of this prospectus:
•
offer, sell, contract to sell, announce the intention to sell or pledge any of the common units;
•
grant or sell any option or contract to purchase any of the common units;
•
enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or
indirectly, any of the common units; or
•
dispose of or hedge any of the common units or securities convertible into or exchangeable for common units.
The 180-day restricted period described in the preceding paragraph will be automatically extended if:
•
during the last 17 days of the 180-day restricted period the trust issues a release concerning earnings or distributable cash or announces material news
or a material event relating to the trust occurs; or
•
prior to the expiration of the 180-day restricted period, the trust announces that it will issue a release announcing earnings or distributable
cash during the 16-day period following the last day of the 180-day period, in which case the restrictions described in the preceding
paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the release or the announcement of
the material news or material event.
The representatives have informed Chesapeake that they do not presently intend to release common units or other securities subject to the lock-up agreements.
Any determination to release any common units or other securities subject to the lock-up agreements would be based on a number of factors at the time of any such
determination; such factors may include the market price of the common units, the liquidity of the trading market for the common units, general market conditions, the
number of common units or other securities subject to the lock-up agreements proposed to be sold, and the timing, purpose and terms of the proposed sale.
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In order to facilitate the offering of the common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the
common units. In connection with the offering, the underwriters may purchase and sell common units in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of common units
than they are required to purchase in the offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A
“covered short position” is a short position that is not greater than the amount of additional common units for which the underwriters’ option described above may be
exercised. The underwriters can close out a covered short sale by exercising their option to purchase additional common units or purchasing units in the open market. In
determining the source of units to close out a covered short sale, the underwriters will consider, among other things, the open market price of units compared to the
price available under their option to purchase additional common units. The underwriters may also sell units in excess of their option to purchase additional common
units, creating a naked short position. The underwriters must close out any naked short position by purchasing units in the open market. A naked short position is more
likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could
adversely affect investors who purchase in this offering. As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units
in the open market to stabilize the price of the common units. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer
for distributing the common units in the offering, if the syndicate repurchases previously distributed common units in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. These activities may raise or maintain the market price of the common units above independent market levels or prevent or retard
a decline in the market price of the common units. The underwriters are not required to engage in these activities and may end any of these activities at any time.
The following table shows the amount per unit and total underwriting discounts and commissions the trust will pay to the underwriters (dollars in thousands,
except per unit). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.
Paid by the Trust
No Exercise
Full Exercise
Per Common Unit
Total
$
$
$
$
In addition, the trust will pay Morgan Stanley & Co. LLC and Raymond James & Associates, Inc. an aggregate structuring fee of $
underwriters exercise their option to purchase additional common units in full) for evaluation, analysis and structuring of the trust.
(or $
if the
Chesapeake estimates that the expenses payable by Chesapeake and the trust, excluding underwriting discounts and commissions, in connection with this
offering will be approximately $2.6 million. The underwriters have agreed to reimburse Chesapeake for up to $150,000 in expenses incurred by it in connection with
this offering.
Chesapeake, the trust and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act of 1933.
Prior to this offering, there has been no public market for trust units. The initial public offering price was determined by negotiations between Chesapeake and
the representatives. Among the factors considered in determining the initial public offering price were estimates of distributions to trust unitholders, overall quality of
the oil, natural gas liquids and natural gas to be produced from the Underlying Properties, industry and market conditions, the information set forth in this prospectus or
otherwise available to the representatives and the general conditions of the securities market at the time of this offering.
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The estimated initial public offering price range set forth on the cover page of this prospectus is subject to change as a result of market conditions and other
factors. The trust and the underwriters cannot assure you that the prices at which the common units will sell in the public market after this offering will not be lower
than the initial public offering price or that an active trading market in the trust’s common units will develop and continue after this offering.
Because the Financial Industry Regulatory Authority, or FINRA, views the common units offered under this prospectus as interests in a direct participation
program, the offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units should be judged similarly
to the suitability with respect to other securities that are listed for quotation on a national securities exchange.
The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading,
commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage
activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory,
investment banking, commercial banking and other services for Chesapeake and its affiliates, for which they received or will receive customary fees and expenses.
Affiliates of Morgan Stanley & Co. LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., Wells Fargo Securities, LLC, Barclays Capital Inc., BNP Paribas
Securities Corp., Citigroup Global Markets Inc., Credit Agricole Securities (USA) Inc., Credit Suisse Securities (USA) LLC, Mitsubishi UFJ Securities (USA), Inc.,
Mizuho Securities USA Inc., Natixis Securities Americas LLC, RBS Securities Inc., Scotia Capital (USA) Inc., UBS Securities LLC, Comerica Securities, Inc., Banco
Bilbao Vizcaya Argentaria, S.A., DnB NOR Markets, Inc., Macquarie Capital (USA) Inc., Nomura Securities International, Inc., PNC Capital Markets LLC, SMBC
Nikko Capital Markets Limited, SunTrust Robinson Humphrey, Inc. and TD Securities (USA) LLC are lenders under Chesapeake’s revolving credit facility and, in that
respect, will receive a substantial portion of the net proceeds from this offering through the repayment of borrowings outstanding under such credit facility.
In addition, affiliates of Morgan Stanley & Co. LLC, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Agricole Securities (USA) Inc., RBS
Securities Inc., Scotia Capital (USA) Inc., UBS Securities LLC, Comerica Securities, Inc., Banco Bilbao Vizcaya Argentaria, DnB NOR Markets, Inc., Nomura
Securities International, Inc., S.A., SMBC Nikko Capital Markets Limited, SunTrust Robinson Humphrey, Inc., and TD Securities (USA) LLC are lenders under the
revolving bank credit facility of Chesapeake Midstream Development. Affiliates of Morgan Stanley & Co. LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co.,
Wells Fargo Securities, LLC, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Agricole Securities (USA) Inc., Credit Suisse Securities (USA) LLC, RBS
Securities Inc., Scotia Capital (USA) Inc., UBS Securities LLC, Comerica Securities, Inc., Banco Bilbao Vizcaya Argentaria, S.A., SMBC Nikko Capital Markets
Limited and TD Securities (USA) LLC are lenders under the revolving bank credit facility of Chesapeake Midstream Partners, L.P. Affiliates of Morgan Stanley & Co.
LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., Wells Fargo Securities, LLC, Barclays Capital Inc., BNP Paribas Securities Corp., Credit Agricole
Securities (USA) Inc., Credit Suisse Securities (USA) LLC, Natixis Securities Americas LLC, Scotia Capital (USA) Inc., Macquarie Capital (USA) Inc., Nomura
Securities International, Inc. and TD Securities (USA) LLC are counterparties to Chesapeake’s multi-counterparty secured hedging facility, and an affiliate of Wells
Fargo Securities, LLC acts as collateral agent under such facility. Deutsche Bank Securities Inc., Citigroup Global Markets Inc. and RBS Securities Inc. acted as Deal
Managers for Chesapeake’s tender offer for various tranches of its contingent convertible senior notes in April 2011. Affiliates of certain of the underwriters are parties
to volumetric production payment transactions with Chesapeake and will be counterparties to hedging contracts with the trust.
Furthermore, certain of the underwriters and their respective affiliates may, from time to time, enter into arms-length transactions with the trust in the ordinary
course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the
underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities)
and financial instruments (including bank loans) for their
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own account and for the accounts of their customers, and such investment and securities activities may involve securities or instruments of the trust or Chesapeake or
their affiliates. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect
of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.
A prospectus in electronic format may be made available on websites maintained by one or more underwriters, or selling group members, if any, participating in
this offering. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. Internet
distributions will be allocated by the representatives to the underwriters that may make Internet distributions on the same basis as other allocations.
At the request of Chesapeake, the underwriters have reserved for sale, at the initial public offering price, up to 5% of the common units offered hereby for
Chesapeake’s directors, officers, and certain other persons associated with Chesapeake. The sales will be made by Morgan Stanley & Co. LLC through a directed unit
program. It is not certain if these persons will choose to purchase all or any portion of these reserved units, but any purchases they make will reduce the number of
common units available to the general public. To the extent the allotted reserved units are not purchased in the directed unit program, we will offer these common units
to the general public on the same basis as all other common units offered by this prospectus. The individuals eligible to participate in the directed unit program must
commit to purchase no later than before the opening of business on the day following the date of this prospectus, but in any event, will not be obligated to purchase
common units. Persons purchasing reserved units in the directed unit program will not be subject to a lock-up agreement. Chesapeake has agreed to indemnify Morgan
Stanley & Co. LLC against certain liabilities and expenses, including liabilities under the Securities Act of 1933, in connection with the sales of the reserved units.
Notice to Prospective Investors in the EEA
In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from
and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities
described in this prospectus may not be made to the public in that relevant member state other than:
•
to any legal entity which is a qualified investor as defined in the Prospectus Directive;
•
to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal
persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the
prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or
•
in any other circumstances falling within Article 3(2) of the Prospectus Directive;
provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by
any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the
securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression
“Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant
Member State), and includes any relevant implementing measure in the Relevant Member State, and includes any relevant implementing measure in each relevant
member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.
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We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by
the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the
underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.
Notice to Prospective Investors in the United Kingdom
The trust may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a
“recognized collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorized or otherwise approved. As an unregulated scheme, it
cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to,
and is only directed at:
(1) if the trust is a CIS and is marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the
Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth
companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or
(2) otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and
Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and
(3) in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).
The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged
in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.
An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common
units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which
Section 21(1) of FSMA does not apply to the trust.
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LEGAL MATTERS
Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the common units. Bracewell & Giuliani
LLP, counsel to Chesapeake, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus
captioned “U.S. Federal Income Tax Considerations” beginning on page 95. Commercial Law Group, P.C. will pass upon certain other matters for Chesapeake. Certain
legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
Certain information appearing in this prospectus regarding the June 30, 2011 estimated quantities of reserves of the Underlying Properties and royalty interests
owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived
from estimates prepared by Ryder Scott Company, L.P., independent petroleum engineers.
Certain estimates of Chesapeake’s proved reserves of oil and natural gas that are incorporated by reference in this prospectus were based in part upon
engineering reports prepared by independent petroleum engineers Ryder Scott Company, L.P., Netherland, Sewell & Associates, Inc., Data and Consulting Services, a
division of Schlumberger Technology Corporation, and Lee Keeling and Associates, Inc. These estimates are referred to or incorporated by reference herein in reliance
on the authority of such firms as experts in such matters.
The financial statements of Chesapeake and management’s assessment of the effectiveness of internal control over financial reporting (which is included in
Management’s Report on Internal Control over Financial Reporting) incorporated in this prospectus by reference to Chesapeake’s Annual Report on Form 10-K for the
year ended December 31, 2010 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm,
given on the authority of said firm as experts in auditing and accounting.
The Statements of Revenues and Direct Operating Expenses of the Chesapeake Colony Granite Wash Underlying Properties for the years ended December 31,
2008, 2009 and 2010, included in this prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public
accounting firm, given on the authority of said firm as experts in auditing and accounting.
The Statement of Assets and Trust Corpus of Chesapeake Granite Wash Trust as of June 30, 2011, included in this prospectus, has been so included in reliance
on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and
accounting.
WHERE YOU CAN FIND MORE INFORMATION
The trust and Chesapeake have filed with the SEC a registration statement on Form S-1 and Form S-3, respectively, regarding the common units. This
prospectus does not contain all of the information found in the registration statement. For further information regarding the trust, Chesapeake and the common units
offered by this prospectus, you may wish to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration
statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC
at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room
maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at
1-800-SEC-0330. The SEC maintains a website on the Internet at http://www.sec.gov . The trust’s and Chesapeake’s registration statement, of which this prospectus
constitutes a part, can be downloaded from the SEC’s web site.
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Chesapeake files annual, quarterly and current reports, proxy statements and other information with the SEC (File No. 001-13726) pursuant to the Exchange Act.
Chesapeake’s SEC filings are available to the public through the SEC’s website. The trust will file annual, quarterly and current reports and other information with the
SEC following its initial public offering.
This prospectus includes through incorporation by reference certain of the reports and other information that Chesapeake has filed with the SEC. This means that
Chesapeake is disclosing important information to you by referring to those documents. Chesapeake hereby incorporates by reference into this prospectus the
documents listed below that Chesapeake has filed with the SEC and any future filings that it makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the
Exchange Act (excluding any information furnished under Item 2.02 or Item 7.01 on any Current Report on Form 8-K) prior to the later of (i) the closing date of the
offering and (ii) the completion of the offering of the common units, which will automatically update and supersede information in this prospectus:
•
Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 1, 2011;
•
Chesapeake’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011, filed with the SEC on May 10, 2011, and June 30, 2011, filed
with the SEC on August 9, 2011; and
•
Chesapeake’s Current Reports on Form 8-K filed with the SEC on January 24, 2011, February 3, 2011, February 9, 2011, February 22,
2011, February 25, 2011, March 7, 2011, April 5, 2011, April 8, 2011, April 29, 2011, May 5, 2011, May 19, 2011, June 9, 2011, June 16, 2011,
August 4, 2011 and September 23, 2011.
Chesapeake’s recent annual, quarterly and current reports, and any amendments thereto, that it files with the SEC are made available, free of charge, over the
Internet through Chesapeake’s website at www.chk.com as soon as reasonably practicable after Chesapeake electronically files them with or furnishes them to the
SEC. Please note that Chesapeake’s website and the information contained in and linked to it are not incorporated in this prospectus.
Chesapeake will provide without charge to each person to whom this prospectus is delivered, upon written or oral request of such person, a copy of any or all
documents incorporated by reference in this prospectus. Requests for such copies should be directed to Chesapeake at the following address and telephone number:
Jennifer M. Grigsby
Senior Vice President, Treasurer and Corporate Secretary
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Telephone: (405) 848-8000
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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND TERMS RELATED TO THE TRUST
In this prospectus the following terms have the meanings specified below.
Area of Mutual Interest or AMI. Area within the Colony Granite Wash formation identified in the inside front cover of this prospectus.
bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
bcf. Billion cubic feet.
bbtu. One billion btu.
bcfe. Billion cubic feet of natural gas equivalent, determined using a ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
boe. A boe is determined using the ratio of six mcf of natural gas to one bbl of oil, condensate or natural gas liquids, which approximates the relative energy
content of oil, condensate and natural gas liquids as compared to natural gas. Despite holding the ratio constant at six mcf to one bbl, prices have historically often been
higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially
lower.
btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a
dry well, the reporting to the appropriate authority that the well has been abandoned.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at the original reservoir temperature and pressure, but that, when produced, is in the
liquid phase at surface pressure and temperature.
Developed acreage. The number of acres assignable to productive wells.
Development Area. The sections adjacent to governmental sections in the AMI.
Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with
existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through
installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development
activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the
proved reserves, (ii) drill and equip Development Wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well
equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install production facilities such as leases, flow lines,
separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal
systems, and (iv) provide improved recovery systems.
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Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry well. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably
expected to exceed, the costs of the operation. The value of the products that generate revenue is determined at the terminal point of oil and gas producing activities as
defined in Rule 4-10(a)(16) of Regulation S-X under the Securities Act.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or
stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic
barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms
“structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces,
plays or areas of interest.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal wells. Wells which are drilled at angles greater than 70 degrees from vertical.
mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
mboe. One thousand boe.
mcf. One thousand cubic feet.
mcfe. One thousand cubic feet of natural gas equivalent, determined using a ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas
liquids.
mmboe. One million boe.
mmbtu. One million btus.
mmcf. One million cubic feet.
mmcfe. One million cubic feet of natural gas equivalent, determined using a ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas
liquids.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Net revenue interest. A share of production after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest.
NYMEX. New York Mercantile Exchange.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or
to the surface. Oklahoma regulations require plugging of abandoned wells.
Present value of future net revenues (“PV-10”). The present value of estimated future net revenue to be generated from the production of proved reserves,
discounted using an annual discount rate of 10% (as required by the SEC), calculated without deducting future income taxes.
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Production expenses.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment
and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced.
Examples of production expenses (sometimes called lifting expenses) are:
(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E) Severance taxes.
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining and marketing
activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become
exploration, development or production expenses, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development
costs are not production expenses but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
Producing well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production
exceeds production expenses and taxes.
Productive well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved developed reserves. Reserves that are both proved and developed.
Proved reserves. Proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of a reservoir considered as proved includes
(a) the area indentified by drilling and limited by fluid contacts, if any, and (b) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged
to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of
information on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience,
engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has
defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of
the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be
produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification
when (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which
the project or program was based and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing
economic conditions include prices and
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costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the
period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped (PUD) reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater
distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled
to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for
which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in
the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
PV-10. See “Present value of future net revenues.”
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible as of a given date, by application of
development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the
project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as
economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of
reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered
accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock
or water barriers and is individual and separate from other reservoirs.
Standardized Measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil and
natural gas reserves, less future development and production expenses and future income tax expenses, discounted at 10% per annum to reflect timing of future cash
flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the
effect of future income taxes on future net revenues. Because the trust does not bear income taxes, PV-10 and standardized measure with respect to the Royalty Interests
are the same.
tcfe. One trillion cubic feet of natural gas equivalent, determined using a ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil
or natural gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of
production.
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FINANCIAL STATEMENTS
TABLE OF CONTENTS
CHESAPEAKE GRANITE WASH UNDERLYING PROPERTIES
Report of Independent Registered Public Accounting Firm
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2008, 2009 and 2010 and the Six Months Ended June 30,
2010 and 2011
Notes to Statements of Revenues and Direct Operating Expenses
CHESAPEAKE GRANITE WASH TRUST
Report of Independent Registered Public Accounting Firm
Statement of Assets and Trust Corpus as of June 30, 2011
Notes to Statement of Assets and Trust Corpus
F-2
F-3
F-4
F-9
F-10
F-11
UNAUDITED PRO FORMA FINANCIAL INFORMATION
Unaudited Pro Forma Statement of Assets and Trust Corpus as of June 30, 2011
Unaudited Pro Forma Statement of Distributable Income for the Trust for the Year Ended December 31, 2010 and the Six Months Ended June 30, 2011
F-15
F-16
F-17
Notes to Unaudited Pro Forma Financial Information
F-1
Table of Contents
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To Board of Directors and Shareholders of Chesapeake Energy Corporation:
We have audited the accompanying statements of revenues and direct operating expenses of the Chesapeake Granite Wash Underlying Properties, as defined in
Note 1, for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of Chesapeake Energy Corporation’s
management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses of the Underlying Properties are free
of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements of revenues and direct
operating expenses of the Underlying Properties. An audit also includes assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Underlying Properties
for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
The accompanying statements reflect the revenues and direct operating expenses of the Underlying Properties as described in Note 1 to the financial statements
and are not intended to be a complete presentation of the financial position, results of operations or cash flows of the Underlying Properties.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
July 7, 2011
F-2
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Index to Financial Statements
CHESAPEAKE GRANITE WASH UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(In thousands)
2008
Year Ended
December 31,
2009
2010
$ 159,798
$ 123,594
$ 168,347
$ 87,533
Direct operating expenses:
Production expenses excluding ad valorem taxes
Ad valorem taxes
Production taxes
2,867
13
4,604
3,195
14
2,521
5,542
27
3,271
2,385
27
1,903
3,479
—
1,929
Total direct operating expenses
7,484
5,730
8,840
4,315
5,408
$ 152,314
$ 117,864
$ 159,507
$ 83,218
Oil, natural gas liquids and natural gas revenues(a)
Revenues in excess of direct operating expenses
(a)
Six Months Ended
June 30,
2010
2011
(unaudited)
$
$
80,374
74,966
Oil, natural gas liquids and natural gas revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and marketing
expenses.
The accompanying notes are an integral part of these financial statements.
F-3
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Index to Financial Statements
CHESAPEAKE GRANITE WASH UNDERLYING PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1.
Basis of Presentation
The accompanying statements present the revenues and direct operating expenses for the years ended December 31, 2008, 2009 and 2010 and the six months
ended June 30, 2010 and 2011 of ownership interests in certain oil and natural gas properties located in Washita County in western Oklahoma (the “Underlying
Properties”) owned by Chesapeake Energy Corporation (“Chesapeake”) from which royalty interests to be conveyed to Chesapeake Granite Wash Trust (the “Trust”)
will be derived.
The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical
accounting records of Chesapeake. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the
Underlying Properties. Oil, natural gas liquids and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when
delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of existing overriding and other royalties due to
third parties and post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and marketing expenses. Direct
operating expenses include lease and well repairs, maintenance, utilities, payroll, production taxes and other direct operating expenses. The amounts presented represent
100% of Chesapeake’s interests in the Underlying Properties.
During the periods presented, the Underlying Properties were not accounted for as a separate division by Chesapeake and therefore certain costs such as
depreciation, depletion and amortization, accretion of asset retirement obligation, general and administrative expenses and interest were not allocated to the individual
properties. Historical statements reflecting financial position, results of operations and cash flows from operating, investing and financing activities prepared in
accordance with generally accepted accounting principles are not presented because the information necessary to prepare such statements is neither readily available on
an individual property basis nor practicable to obtain in these circumstances. Financial information for the six months ended June 30, 2010 has been presented on a
basis consistent with the financial information for the six months ended June 30, 2011 in order to provide comparability between periods presented. Accordingly, the
statements of revenues and direct operating expenses of the Underlying Properties are presented in lieu of the financial statements required under Rule 3-01 and 3-02 of
the Securities and Exchange Commission Regulation S-X.
The statements of revenues and direct operating expenses for the six months ended June 30, 2010 and 2011 are unaudited and should be read in conjunction with
the financial statement for the year ended December 31, 2010. Such interim financial statements have been prepared on the same basis as the annual financial statement.
In the opinion of Chesapeake, all adjustments, which consist of normal recurring adjustments, necessary to state fairly the information in the unaudited statements have
been included.
2.
Subsequent Events
Events occurring after December 31, 2010 were evaluated through October 17, 2011 to ensure that any subsequent events that met the criteria for recognition
and/or disclosure in this report have been included.
3.
Supplemental Oil, Natural Gas Liquids and Natural Gas Reserve and Standardized Measure Information (Unaudited)
The following oil, natural gas liquids and natural gas reserve information was prepared by Chesapeake based upon information provided by Chesapeake and its
independent petroleum engineers and is presented in accordance with ASC Topic 932, Extractive Activities—Oil and Gas.
F-4
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Index to Financial Statements
Oil and Gas Reserve Quantities
Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods,
and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. Based on reserve reporting rules effective December 31, 2009, the price is calculated using the average price during
the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for
each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir
considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with
reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering
data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless
geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well
penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally
higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the
proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the
operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including
governmental entities.
Proved developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment
and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Chesapeake’s oil and natural gas reserves are presented in accordance with regulations prescribed by the Securities and Exchange Commission as in effect as of
the date of such estimates. Chesapeake emphasizes that reserve estimates are inherently imprecise. Chesapeake’s reserve estimates are generally based upon
extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such
changes could be material and occur in the near term as future information becomes available.
The following table presents the estimated proved and proved developed oil, natural gas liquids and natural gas reserves of the Underlying Properties and the
related summary of changes in estimated quantities of net remaining proved reserves during the years ended December 31, 2010, 2009 and 2008. These reserves
represent the total proved reserves for the remaining economic life of the Underlying Properties and do not represent the reserves that will be owned by the trust.
F-5
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Index to Financial Statements
Natural Gas
Liquids
(mmbls)
Oil
(mbbls)
Natural Gas
(mmcf)
Total
(mboe)
Proved Reserves:
December 31, 2010
Proved reserves, beginning of period
Extensions, discoveries and other additions(a)
Revisions of previous estimates
Production
Sale of reserves-in-place
9,335
2,688
(661)
(855)
21,349
4,768
(2,859)
(1,494)
221,552
55,444
(13,105)
(14,713)
67,609
16,697
(5,704)
(4,801)
—
—
47
—
106
—
1,526
407
10,554
21,870
250,704
74,208
Proved developed reserves:
Beginning of period
2,402
6,166
64,192
19,267
End of period
2,493
6,002
74,033
20,834
3,831
5,465
12,766
126,674
37,709
10,501
112,454
34,709
(672)
(1,266)
(4,632)
(13,192)
(490)
(4,387)
—
Purchase of reserves-in-place
Proved reserves, end of period
December 31, 2009
Proved reserves, beginning of period
Extensions, discoveries and other additions(a)
Revisions of previous estimates
954
Production
Sale of reserves-in-place
(922)
—
7
—
20
—
248
68
Proved reserves, end of period
9,335
21,349
221,552
67,609
Proved developed reserves:
Beginning of period
1,054
4,317
42,748
12,496
End of period
2,402
6,166
64,192
19,267
6,114
65,116
19,288
6,765
744
(900)
71,054
(1,059)
(8,931)
20,947
361
(3,028)
—
Purchase of reserves-in-place
December 31, 2008
Proved reserves, beginning of period
2,321
Extensions, discoveries and other additions(a)
2,340
Revisions of previous estimates
Production
Sale of reserves-in-place
(207)
(639)
—
Purchase of reserves-in-place
Proved reserves, end of period
—
43
494
141
12,766
126,674
37,709
2,109
22,424
6,606
4,317
42,748
12,496
3,831
Proved developed reserves:
Beginning of period
760
End of period
(a)
—
16
1,054
Extensions and discoveries for the years ended December 31, 2008, 2009 and 2010 are a result of the discovery and production from wells drilled horizontally in the Colony Granite
Wash formation in Washita County, Oklahoma on acreage leased by Chesapeake. The formation had previously been drilled and produced from vertical wells. During the years
ended December 31, 2008, 2009 and 2010, Chesapeake drilled or participated in the drilling of 11, 8 and 11 net wells, respectively, from which a portion of royalty interests conveyed
to the Trust will be derived. These wells demonstrated consistent levels of production and provided reasonable certainty that wells to be drilled within the acreage qualified for Proved
Undeveloped classification.
F-6
Table of Contents
Index to Financial Statements
Standardized Measure of Discounted Future Net Cash Flows
Certain information concerning the assumptions used in computing the valuation of proved developed reserves and their inherent limitations are discussed
below. Chesapeake believes such information is essential for a proper understanding and assessment of the data presented. These assumptions are summarized as
follows:
•
Pricing is applied based upon the trailing 12-month unweighted average market prices, using the first-day-of-the-month price for each month, at
December 31, 2009 and 2010. For December 31, 2008, pricing is applied based on the spot price of oil and natural gas on December 31, 2008. The
prices, before field differentials, for the Underlying Properties’ proved reserves and future net revenues were as follows:
Oil and natural gas liquids (per bbl)
Natural gas (per mcf)
2008
December 31,
2009
2010
$ 44.61
$ 5.71
$ 61.14
$ 3.87
$ 79.42
$ 4.38
•
Future development and production costs are determined based upon actual cost at period end.
•
Future development costs and the standardized measure of discounted future net cash flows includes projections of future abandonment costs at period
end.
•
An annual discount factor of 10% is applied to the future net cash flows, as required by SEC rules.
Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties.
Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The
standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Underlying Properties’ oil
and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and
anticipated future changes in prices and costs. The following table presents future net cash flows relating to the Underlying Properties based on the standardized
measure in ASC Topic 932 (in thousands).
Future cash inflows
Future production expenses
Future development costs(a)
Future income taxes
2008
December 31,
2009
2010
$ 1,066,764
(131,270)
(185,633)
(239,076)
$ 1,675,680
(195,960)
(323,981)
(391,903)
$ 2,503,300
(275,690)
(494,207)
(622,628)
510,785
(267,167)
763,836
(437,903)
1,110,775
(618,831)
Future net cash flows
Less effect of a 10% discount factor
Standardized measure of discounted future net cash flows
(a)
$
Includes future abandonment costs.
F-7
243,618
$
325,933
$
491,944
Table of Contents
Index to Financial Statements
Changes in the standardized measure of future net cash flows related to proved oil and natural gas reserves are as follows for the years ended December 31,
2008, 2009 and 2010.
2008
2009
(In thousands)
2010
Standardized measure, beginning of period
Sales of natural gas and oil produced, net of production costs
Net changes in prices and production expenses
Extensions and discoveries, net of production and development costs
Changes in future development costs
Development costs incurred during the period that reduce future development costs
Revisions of previous quantity estimates
Purchase of reserves in place
Accretion of discount
Net change in income taxes
Changes in production rates and other(a)
$
189,132
(152,314)
(65,781)
273,652
14,200
12,851
(27,468)
2,228
28,003
(26,186)
(4,699)
$
243,618
(117,864)
(61,564)
292,419
27,119
10,939
(14,728)
761
36,070
(50,913)
(39,924)
$
325,933
(159,507)
24,208
172,181
(10,321)
33,441
117,618
6,579
49,393
(104,512)
36,931
Standardized measure, end of period
$
243,618
$
325,933
$
491,944
(a)
The change in production rates and other are related to revisions in estimated time of production and development.
F-8
Table of Contents
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Chesapeake Energy Corporation and the Unitholders of Chesapeake Granite Wash Trust:
We have audited the accompanying statement of assets and trust corpus of Chesapeake Granite Wash Trust as of June 30, 2011. This financial statement is the
responsibility of Chesapeake Energy Corporation. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the statement of assets and trust corpus is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
As described in Note 2, this financial statement was prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, the financial statement referred to above presents fairly, in all material respects, the assets and trust corpus of Chesapeake Granite Wash Trust at
June 30, 2011, on the basis of accounting described in Note 2.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
July 7, 2011
F-9
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
STATEMENT OF ASSETS AND TRUST CORPUS
As of
June 30, 2011
Assets:
Cash
$
1,000
Total Assets
$
1,000
Trust Corpus:
Trust corpus
$
1,000
Total
$
1,000
The accompanying notes are an integral part of this statement.
F-10
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS
1.
Organization of the Trust
Chesapeake Granite Wash Trust (the “Trust”) is a statutory trust formed on June 29, 2011 and funded on June 30, 2011 under the Delaware Statutory Trust Act
pursuant to a Trust Agreement (the “Trust Agreement”) among and by Chesapeake Energy Corporation (“Chesapeake”), as trustor, The Bank of New York Mellon
Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”).
The Trust was created to acquire and hold royalty interests for the benefit of Trust unitholders pursuant to a trust agreement among Chesapeake, the Trustee and
the Delaware Trustee. These royalty interests are interests in underlying properties consisting of Chesapeake’s interests in specified oil and gas properties located in the
Colony Granite Wash formation in Washita County in western Oklahoma (the “Underlying Properties”). After the conveyance of the royalty interests, Chesapeake will
retain interests in each of the Underlying PDP Properties and Underlying Development Properties. The Trust Agreement will provide that the Trust’s business activities
will be limited to owning the royalty interests and any activity reasonably related to such ownership including activities required or permitted by the terms of the
conveyances related to the royalty interests and oil and natural gas liquids hedging activities, as described below.
The Trust will enter into a development agreement with Chesapeake that will obligate Chesapeake to drill, or cause to be drilled, the equivalent of 118 horizontal
oil and natural gas development wells (as defined in the development agreement) in the AMI by June 30, 2016. Additionally, Chesapeake will agree not to drill or
complete, or allow another person within its control to drill or complete, any other well in the AMI other than the development wells until Chesapeake has fulfilled its
drilling obligation. A wholly owned subsidiary of Chesapeake will grant to the Trust a lien (the “Drilling Support Lien”) covering its interest in the AMI (except the
Underlying PDP Properties or any other wells already producing and not subject to the royalty interests) in order to secure the estimated amount of the drilling costs for
the Trust’s interests in the Underlying Development Properties. These liens will be released over time as Chesapeake fulfills its drilling obligation under the
development agreement. If Chesapeake does not fulfill its drilling obligation by June 30, 2016, the Trust may foreclose on the Drilling Support Lien to the extent of
Chesapeake’s remaining interest in the AMI.
The Trust will enter into an administrative services agreement with Chesapeake pursuant to which Chesapeake will provide the Trust with certain accounting,
tax preparation, bookkeeping, hedge management and informational services related to the royalty interests and the registration rights agreement. In return for these
services, the Trust will pay Chesapeake an annual fee of $200,000 in addition to reimbursement for Chesapeake’s actual out-of-pocket fees, costs and expenses incurred
in connection with the provision of any of the services under the agreement. The administrative services agreement will terminate on the earliest of: (i) the date the
Trust shall have been wound up in accordance with the trust agreement, (ii) termination of the royalty interests or disposal of the royalty interests held by the Trust,
(iii) if properties are transferred by Chesapeake to a third party, upon 90-days written notice by either Chesapeake or the Trustee, provided Chesapeake has met its
drilling obligation and the transferee of such properties agrees to assume responsibility to provide the services in place of Chesapeake, or (iv) a date mutually agreed by
Chesapeake and the Trustee.
The Trust will be a party to certain oil and natural gas liquids commodity price hedges pursuant to which the Trust will receive payments directly from its
counterparties and will be required to pay any amounts owed directly to its counterparties. Chesapeake will have authority, in its role as hedge manager to the Trust, to
terminate, restructure or otherwise modify all or any portion of the Trust’s hedging arrangements to the extent that Chesapeake reasonably determines, acting in good
faith, that the oil and natural gas liquids volumes hedged under such portion of the contracts exceed, or are expected to exceed, the combined estimated oil and natural
gas liquids production attributable to the Trust’s royalty interests over the periods hedged, and the counterparties may
F-11
Table of Contents
Index to Financial Statements
require Chesapeake to terminate, restructure or otherwise modify the hedging arrangements under certain circumstances. The Trust’s royalty interests in the Underlying
Properties will be pledged as collateral under the Trust’s hedging arrangements. Subject to any applicable notice and cure periods, if, among other things, the Trust or
Chesapeake is in material default of the drilling, payment or reporting obligations set forth in the hedging arrangements, the hedge counterparties may foreclose on the
lien on the Trust’s royalty interests.
The Trust will dissolve and begin to liquidate on June 30, 2031 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. 50% of each
of the PDP Royalty Interest and the Development Royalty Interest will automatically revert to Chesapeake at the Termination Date, while the remaining royalty
interests will be sold and the proceeds will be distributed to the Trust unitholders at the Termination Date or soon thereafter. Chesapeake will have a right of first refusal
to purchase the remaining 50% of the royalty interests at the Termination Date.
2.
Significant Accounting Policies
The following is a summary of the significant accounting policies followed by the Trust.
Basis of Accounting. The financial statements of the Trust are prepared on the following basis:
•
Revenues, including the effects of oil and natural gas liquids commodity price hedges, are recorded when received and distributions to Trust
unitholders are recorded when paid.
•
Trust expenses are recorded when paid.
•
Cash reserves may be established for certain contingencies that would not generally be recorded under generally accepted accounting principles.
•
The investment in royalty interests will be recorded at the historical cost of Chesapeake, which is based on an allocation of the historical net book
value of Chesapeake’s full cost pool according to the fair value of the conveyed royalty interests in the Underlying Properties relative to Chesapeake’s
proved reserves. This investment will be amortized as a single cost center on a units-of-production basis over total proved reserves. This investment
will be comprised of two components, the PDP Royalty Interest and the Development Royalty Interest. The PDP Royalty Interest entitles the Trust to
receive 90% of the net revenues associated with Chesapeake’s interest in the associated producing wells and will be accounted for as an oil and gas
property interest. The Development Royalty Interest entitles the Trust to receive 50% of the net revenues associated with Chesapeake’s interest in the
associated development wells. Although the Drilling Support Lien provides partial recourse to the Trust regarding its ownership in the Development
Royalty Interest until Chesapeake’s drilling obligation is met, which has attributes of a production loan, any proceeds resulting from a foreclosure on
such lien can only be used by the Trust for costs and expenses incident to the foreclosure sale and development drilling. Any remainder would be
distributed to Chesapeake and may not be distributed directly to unitholders. Once the drilling obligation is met, the risks and rewards of the
Development Royalty Interest are similar to the PDP Royalty interest. Therefore, the Trust will also account for the Development Royalty Interest as
an oil and gas property interest. As an entity under common control, the assets of the Trust are reflected at Chesapeake’s historical cost and the
amortization applied to the investment is charged directly to Trust corpus and does not affect distributable income. The Trust will include both the
proved developed reserves associated with the PDP Royalty Interest and the proved undeveloped reserves associated with the Development Royalty
Interest in its supplemental oil and gas disclosures.
•
The Trust will evaluate the carrying value of the investment in royalty interest under the full cost accounting method prescribed by the Securities and
Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, the carrying value of the
investment in royalty interest may not exceed an amount equal to the sum of the present value (using a 10% discount rate) of the estimated future net
revenues (adjusted for qualifying cash flow hedges, if any) from proved reserves. Any write-downs resulting from the ceiling test will be non-cash
charges to Trust corpus and will not affect distributable income.
F-12
Table of Contents
Index to Financial Statements
While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America
(“GAAP”), the modified cash basis of reporting revenues, expenses, and distributions, and the presentation of the proved reserves attributable to both the PDP and
Development Royalty Interests is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on the net cash receipts
generated from the production and sale of the reserves of the Underlying Properties. This comprehensive basis of accounting other than GAAP corresponds to the
accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of
Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer
revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the
modified cash basis as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.
Cash. Cash consists of highly liquid instruments with maturities of three months or less at the time of acquisition.
Use of Estimates. The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and
liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
3.
Income Taxes
The Trust is a Delaware statutory trust that is treated as a partnership for federal income tax purposes. The Trust is not required to pay federal or state income
taxes.
4.
Distributions to Unitholders
The Trust will make quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust’s expenses, approximately 60 days following
the completion of each quarter through (and including) the quarter ending June 30, 2031, the Termination Date. The first distribution, which will cover the third quarter
of 2011 (consisting of proceeds attributable to two months of production), is expected to be made on or about December 1, 2011 to record unitholders on or about
November 21, 2011. Upon termination of the Trust, 50% of each of the PDP Royalty Interest and the Development Royalty Interest will be sold, and the net proceeds
therefrom will be distributed pro rata to the unitholders soon after the Termination Date. Because payments to the Trust will be generated by depleting assets and the
Trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of original
investment to the unitholders.
5.
Trust Operating Expenses
Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course
expenses as they become due, Chesapeake will lend funds to the Trust necessary to pay such expenses. Any funds loaned by Chesapeake pursuant to this commitment
will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other
accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness. If Chesapeake lends funds pursuant
to this commitment, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such
loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arms’
length transaction between Chesapeake and an unaffiliated third party.
F-13
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statement of distributable income for Chesapeake Granite Wash
Trust (the “Trust”) have been prepared to illustrate the conveyance of royalty interests in certain Chesapeake Granite Wash Underlying Properties (the “Underlying
Properties”) to the Trust by Chesapeake Energy Corporation (“Chesapeake”). The unaudited pro forma statement of assets and trust corpus presents the formation of the
Trust as if it had occurred on June 30, 2011, and giving effect to the royalty interests conveyance as if it occurred on that date. The unaudited pro forma statement of
distributable income presents the statement of historical revenue and direct operating expenses of the Underlying Properties for the year ended December 31, 2010 and
the six months ended June 30, 2011, giving effect to the royalty interests conveyance as of the beginning of the period presented, reflecting only pro forma adjustments
expected to have a continuing impact on the combined results.
These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred
had the royalty interests conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.
These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates
herein could change significantly. The unaudited pro forma statement of distributable income should be read in conjunction with “Discussion and Analysis of Historical
Results from the Producing Wells” included in this prospectus and the historical financial statements of the Trust and the Underlying Properties, including the related
notes, included in this prospectus.
F-14
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
UNAUDITED PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS
AS OF JUNE 30, 2011
(In thousands)
Historical
Assets:
Cash
Investment in Royalty Interest(a)
$
Total Assets
Trust Corpus:
Trust Units Issued and Outstanding(a)
Adjustments
1
—
$
$
1
454,448
1
454,448
454,449
1
454,448
454,449
The accompanying notes are an integral part of this unaudited pro forma financial information.
F-15
—
454,448
Pro Forma
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME
(In thousands, except per unit data)
Six Months
Ended
June 30,
2011
Year Ended
December 31,
2010
Historical results of Underlying Properties:
Oil, natural gas liquids and natural gas revenues(b)
Direct operating expenses:
Production expenses excluding ad valorem taxes
Ad valorem taxes
Production taxes
$
168,347
$
(5,542)
(27)
(3,271)
Revenues in excess of operating expenses before pro forma adjustments
80,374
(3,479)
—
(1,929)
159,507
74,966
5,542
6,035
3,479
3,029
11,577
6,508
Pro forma gross net proceeds
Overriding royalty interest percentage
171,084
90%
81,474
90%
Net proceeds to trust
153,975
73,327
1,000
500
Pro Forma Adjustments:
Direct operating expenses:
Elimination of historical production expenses(c)
Elimination of historical marketing expenses by Chesapeake affiliate(d)
Total pro forma adjustments
Less:
Trust administrative expenses(e)(f)
Distributable income of trust(f)(g)
$
152,975
$
72,827
Distributable income per trust unit(e)(g)(h)
$
3.34
$
1.59
The accompanying notes are an integral part of this unaudited pro forma financial information.
F-16
Table of Contents
Index to Financial Statements
CHESAPEAKE GRANITE WASH TRUST
NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION
1.
Basis of Presentation
Chesapeake Granite Wash Trust (the “Trust”) is a Delaware statutory trust formed in June 2011 by Chesapeake Energy Corporation (“Chesapeake”) to own
royalty interests in 69 producing horizontal oil and gas wells producing from the Colony Granite Wash formation in Washita County in western Oklahoma (the
“Producing Wells”) and royalty interests in 118 horizontal oil and natural gas development wells to be drilled (the “Development Wells”) within an Area of Mutual
Interest (the “AMI”). The AMI consists of approximately 45,400 gross acres (28,700 net acres) in the Colony Granite Wash formation in Washita County, Oklahoma.
Chesapeake is obligated to drill, or cause to be drilled, the Development Wells from its drilling locations in the AMI. Until Chesapeake has satisfied its drilling
obligation, it will not be permitted to drill and complete any well on lease acreage included within the AMI for its own account. Also, a wholly owned subsidiary of
Chesapeake will grant to the Trust a lien (the “Drilling Support Lien”) on Chesapeake’s interest in the AMI (except currently producing wells) in order to secure its
drilling obligation to the Trust. The royalty interests will be conveyed from Chesapeake’s interest in the Producing Wells and the Development Wells in the AMI (the
“Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the Trust to receive 90% of the proceeds (exclusive of any
production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil, natural gas liquids and natural gas production
attributable to Chesapeake’s interest in the Producing Wells. The royalty interest in the Development Wells (the “Development Royalty Interest”) entitles the Trust to
receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil
and natural gas production attributable to Chesapeake’s interest in the Development Wells.
The unaudited pro forma statement of assets and trust corpus assumes formation and funding of the Trust and conveyance of the royalty interests at June 30,
2011. The unaudited pro forma statement of distributable income assumes the conveyance of the royalty interests as of the beginning of the period presented.
In order to provide support for cash distributions on the common units, Chesapeake has agreed to subordinate 11,437,500 of the Trust units it will retain
following this offering (the “subordinated units”), which will constitute 25% of the outstanding Trust units. The subordinated units will be entitled to receive pro rata
distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable
quarterly subordination threshold. If there is insufficient cash to fund such a distribution on all the common units, the distribution to be made with respect to the
subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on
all the common units. Each quarterly subordination threshold is equal to 80% of the target cash distribution level for the corresponding quarter (each, a “subordination
threshold”). In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to Chesapeake to satisfy its drilling
obligation and perform operations in the Underlying Properties in an efficient and cost-effective manner, Chesapeake will be entitled to receive incentive distributions
(the “incentive distributions”) equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 120% of the target
cash distribution for such quarter (each, an “incentive threshold”).
The subordinated units will automatically convert into common units on a one-for-one basis and Chesapeake’s right to receive incentive distributions will
terminate, at the end of the fourth full calendar quarter following Chesapeake’s satisfaction of its drilling obligation to the Trust with respect to the Development Wells.
Chesapeake currently intends that it will complete its drilling obligation on or before June 30, 2015 and that, accordingly, the subordinated units will convert into
common units on or before June 30, 2016. However, Chesapeake will have until June 30, 2016 to drill all the Development Wells, in which event the subordinated units
would convert into common units on or before June 30, 2017. The period during which the subordinated units are outstanding is referred to as the “subordination
period.”
F-17
Table of Contents
Index to Financial Statements
Chesapeake believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction.
The unaudited pro forma financial information should be read in conjunction with the Statement of Assets and Trust Corpus for the Trust and the Statements of
Revenues and Direct Operating Expenses for the Underlying Properties and related notes, respectively, for the periods presented.
2.
Trust Accounting Policies
The Unaudited Pro Forma Statement of Distributable Income was derived from the historical accounting records of the Underlying Properties.
The Trust serves as a pass-through entity, with expenses for depletion, interest and income taxes being based upon the status and elections of the Trust
unitholders. In addition, the royalty interest will not be burdened by pre-production expenses. Thus, the statement purports to show distributable income, defined as
income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses, if any, for depreciation, depletion and
amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties (other than those of the Trust) and have been
reduced by post-production expenses and taxes. Actual cash receipts may vary due to timing delays of actual cash receipts from the property purchasers and due to
wellhead and pipeline volume balancing agreements or practices. While these statements differ from financial statements prepared in accordance with accounting
principles generally accepted in the United States of America (“GAAP”), the modified cash basis of reporting revenues, expenses, and distributions, and the
presentation of the proved reserves attributable to both the PDP and Development Royalty Interests is considered to be the most meaningful because quarterly
distributions to the Trust unitholders are based on the net cash receipts generated from the production and sale of the reserves of the Underlying Properties.
The investment in royalty interests will be recorded at the historical cost of Chesapeake, which is based on an allocation of the historical net book value of
Chesapeake’s full cost pool according to the fair value of the conveyed royalty interests in the Underlying Properties relative to Chesapeake’s proved reserves. This
investment will be amortized as a single cost center on a units-of-production basis over total proved reserves. This investment will be comprised of two components, the
PDP Royalty Interest and the Development Royalty Interest. The PDP Royalty Interest entitles the Trust to receive 90% of the net revenues associated with
Chesapeake’s interest in the associated producing wells and will be accounted for as an oil and gas property interest. The Development Royalty Interest entitles the
Trust to receive 50% of the net revenues associated with Chesapeake’s interest in the associated development wells. Although the Drilling Support Lien provides partial
recourse to the Trust regarding its ownership in the Development Royalty Interest until Chesapeake’s drilling obligation is met, which has attributes of a production
loan, any proceeds resulting from a foreclosure on such lien can only be used by the Trust for costs and expenses incident to the foreclosure sale and development
drilling. Any remainder would be distributed to Chesapeake and may not be distributed directly to unitholders. Once the drilling obligation is met, the risks and rewards
of the Development Royalty Interest are similar to the PDP Royalty interest. Therefore, the Trust will also account for the Development Royalty Interest as an oil and
gas property interest. As an entity under common control, the assets of the Trust are reflected at Chesapeake’s historical cost and the amortization applied to the
investment is charged directly to Trust corpus and does not affect distributable income. The Trust will include both the proved developed reserves associated with the
PDP Royalty Interest and the proved undeveloped reserves associated with the Development Royalty Interest in its supplemental oil and gas disclosures.
3.
Income Taxes
The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income taxes has
been made.
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The following adjustments were made in the preparation of the unaudited pro forma financial information:
(a) Reflects Chesapeake’s conveyance of the royalty interests to the Trust in exchange for all of the net proceeds of this offering as well as 11,437,500 common
units and 11,437,500 subordinated units representing an assumed 50% beneficial interest in the Trust. The investment in royalty interests will be recorded at the
historical cost of Chesapeake, which is based on an allocation of the historical net book value of Chesapeake’s full cost pool according to the fair value of the
conveyed royalty interests in the Underlying Properties relative to the fair value of Chesapeake’s proved reserves. This investment will be amortized as a single cost
center on a units-of-production basis over total proved reserves. This investment will be comprised of two components, the PDP Royalty Interest and the Development
Royalty Interest. The PDP Royalty Interest entitles the Trust to receive 90% of the net revenues associated with Chesapeake’s interest in the associated producing
wells. The Development Royalty Interest entitles the Trust to receive 50% of the net revenues associated with Chesapeake’s interest in the associated development
wells. Although the Drilling Support Lien provides partial recourse to the Trust regarding its ownership in the Development Royalty Interest until Chesapeake’s
drilling obligation is met, which has attributes of a production loan, the Trust will account for the Development Royalty Interest as an oil and gas property interest
because, as an entity under common control, the assets of the Trust are reflected at Chesapeake’s historical cost and the amortization applied to the investment is
charged directly to Trust corpus and does not affect distributable income. The Trust will include both the proved developed reserves associated with the PDP Royalty
Interest and the proved undeveloped reserves associated with the Development Royalty Interest in its supplemental oil and gas disclosures.
(b) Oil and natural gas revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating
and marketing expenses.
(c) Production expenses are not paid by the Trust and, thus, such expenses are being deducted in determining pro forma net gross proceeds.
(d) The Trust will not be charged for costs of marketing services provided by Chesapeake or its affiliates.
(e) The Trust’s expenses are estimated at $1.0 million annually. Such expenses include trustee fees, administrative service fees paid to Chesapeake and costs
associated with being a public entity.
(f) The trustee intends to withhold $1.0 million from the first quarterly distribution to establish an initial cash reserve to cover Trust expenses. The
establishment of such reserve has not been reflected in the pro forma statements of distributable income due to its non-recurring nature.
(g) Assumes that no incentive threshold was reached during the period.
(h) Assumes issuance of 45,750,000 Trust units.
5.
Pro Forma Supplemental Oil and Natural Gas Reserve and Standardized Measure Information
Information with respect to the oil and natural gas producing activities of the Trust’s royalty interests in the Underlying Properties is presented in the following
tables. The information was derived from reserve reports which were prepared by Chesapeake in accordance with ASC Topic 932, Extractive Activities—Oil and Gas.
Oil and Natural Gas Reserve Quantities
Proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods,
and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. Based on reserve reporting rules effective December 31, 2009, the price is calculated using the average price during
the 12-month period prior to the ending date of the period covered by the report, determined as
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Index to Financial Statements
an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it
will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid
contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically
producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are
limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower
contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated
natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable
technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques
(including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with
properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved
for development by all necessary parties and entities, including governmental entities.
Proved developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment
and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Chesapeake’s oil and natural gas reserves are presented in accordance with regulations prescribed by the Securities and Exchange Commission as in effect as of
the date of such estimates. Chesapeake emphasizes that reserve estimates are inherently imprecise. Chesapeake’s reserve estimates are generally based upon
extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such
changes could be material and occur in the near term as future information becomes available.
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The following table presents the estimated remaining proved and proved developed oil, natural gas liquids, and natural gas reserves of the Trust’s royalty
interests in the Underlying Properties, all of which are located in the continental United States, estimated by Chesapeake and its independent petroleum engineers, and
the related summary of changes in estimated quantities of net remaining proved reserves during the year ended December 31, 2010.
Historical
Underlying Properties
Natural
Gas
Liquids
(mmbls)
Natural
Gas
(mmcf)
Oil
(mbbls)
Adjustments
Natural
Gas
Liquids
(mmbls)
Natural
Gas
(mmcf)
Oil
(mbbls)
Pro Forma
Chesapeake Granite Wash
Trust
(a)
Natural
Gas
Liquids
(mmbls)
Natural
Gas
(mmcf)
Oil
(mbbls)
December 31, 2010
Proved reserves,
beginning of
period
9,335
221,552
21,349
(3,611)
(94,327)
(9,094)
5,724
127,225
12,255
Extensions,
discoveries and
other additions
2,688
55,444
4,768
(1,208)
(26,460)
(2,441)
1,480
28,984
2,327
(13,105)
(14,713)
(2,859)
(1,494)
227
85
7,680
1,471
1,472
150
(5,425)
(13,242)
(1,387)
(1,344)
Revisions of previous
estimates
(661)
(855)
Production
Sale of
reserves-in-place
Purchase of
reserves-in-place
(434)
(770)
—
—
—
—
—
—
—
—
—
47
1,526
106
(14)
(448)
(36)
33
1,078
70
Proved reserves, end
of period
10,554
250,704
21,870
(4,521)
(112,084)
(9,949)
6,033
138,620
11,921
Proved developed
reserves:
Beginning of
period
2,402
64,192
6,166
(345)
(12,865)
(1,234)
2,057
51,327
4,932
End of period
2,493
74,033
6,022
(388)
(14,728)
(1,200)
2,105
59,305
4,802
Proved undeveloped
reserves:
Beginning of
period
6,933
157,360
15,183
(3,266)
(81,462)
(7,860)
3,667
75,898
7,323
End of period
8,061
176,671
15,868
(4,133)
(97,356)
(8,749)
3,928
79,315
7,119
(a)
Reflects amounts attributable to retained interest of Chesapeake in the Underlying Properties.
We estimate that, as of December 31, 2010, the reserves attributable to the royalty interests that the Trust will own on the termination date of the Trust and
subsequently sell are approximately 4.4 mmboe.
Standardized Measure of Discounted Future Net Cash Flows
Certain information concerning the assumptions used in computing the valuation of proved developed reserves and their inherent limitations are discussed
below. Chesapeake believes such information is essential for a proper understanding and assessment of the data presented. These assumptions are summarized as
follows:
•
Pricing is applied based upon the trailing 12-month unweighted average market prices, using the first-day-of-the-month price for each month, at
December 31, 2010. The calculated unweighted average per unit prices before field differentials for the Underlying Properties’ proved reserves and
future net revenues were $79.42 per barrel of oil and $4.38 per mcf of natural gas.
•
Future development and production costs are determined based upon actual cost at period end.
•
Future development costs and the standardized measure of discounted future net cash flows includes projections of future abandonment costs at period
end.
•
An annual discount factor of 10% is applied to the future net cash flows.
Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties.
Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The
standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Trust’s royalty interests in the
Underlying Properties’ oil and natural gas reserves. An estimate of
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fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and
costs. The following table presents future net cash flows relating to the Underlying Properties and the royalty interests conveyed to the Trust based on the standardized
measure in ASC Topic 932.
December 31, 2010
Historical
Underlying
Properties
Future cash inflows
Future production expenses
Future development costs
Future income taxes
(a)
Adjustments
(In thousands)
$
2,503,300
(275,690)
(494,207)
(622,628)
$
Future net cash flows
Less effect of a 10% discount factor
$
1,110,775
(618,831)
$
Standardized measure of discounted future net cash flows
$
491,944
$
(a)
(b)
(c)
Pro Forma
Chesapeake
Granite Wash
Trust
(1,117,398)
210,585
494,207
622,628
$
1,385,902
(65,105)(b)
—
— (c)
210,022
36,179
$
1,320,797
(582,652)
246,201
$
738,145
Historical cash inflows are net of post-production expenses.
Reflects severance taxes attributable to the Trust’s interest.
Excluded due to the Trust being a pass through entity for tax purposes.
As of December 31, 2010, the present value of the reserves attributable to the royalty interests that the Trust will own on the termination date of the Trust and
subsequently sell was approximately $7.7 million.
Changes in the standardized measure of future net cash flows related to proved oil and natural gas reserves are as follows for the year ended December 31, 2010.
Historical
Underlying
Properties
Pro Forma
Chesapeake
Granite Wash
Trust
Adjustments(a)
(In thousands)
Present value as of December 31, 2009
Sales of oil and natural gas produced, net of production costs
Net changes in prices and production expenses
Extensions and discoveries, net of production and development (c)
Changes in future development costs(d)
Development costs incurred that reduce future development costs
Revisions of previous quantity estimates
Purchase of reserves in place
Accretion of discount
Net change in income taxes
Changes in production rates and other
$
325,933
(159,507)
24,208
172,181
(10,321)
33,441
117,618
6,579
49,393
(104,512)
36,931
$
178,619
5,529(b)
(6,285)
(2,953)
10,321
(33,441)
(24,607)
(498)
1,062
104,512
13,942
$
504,552
(153,978)
17,923
169,228
—
—
93,011
6,081
50,455
—
50,873
Present value as of December 31, 2010
$
491,944
$
246,201
$
738,145
(a)
(b)
(c)
(d)
Reflects amounts attributable to retained interest of Chesapeake in the Underlying Properties.
Production expenses to which the Trust’s interest is not subject and amounts attributable to retained interest of Chesapeake in the Underlying Properties.
Extensions, discoveries and other additions attributable to the retained interest of Chesapeake net of 100% of the future development costs and production expenses attributable to the
Underlying Properties.
Future development costs to which the Trust’s interest is not subject.
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Annex A
Chesapeake Energy Corporation
Estimated
Future Reserves and Income
Attributable to Certain Interests in
Colony Granite Wash Field
SEC Parameters
As of
June 30, 2011
\s\ Don P. Griffin
Don P. Griffin, P.E.
TBPE License No. 64150
Senior Vice President
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
A-1
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Index to Financial Statements
TBPE REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA
SUITE 3800
FAX (713) 651-0849
TELEPHONE (713) 651-9191
HOUSTON, TEXAS 77002-5235
August 10, 2011
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Gentlemen:
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain
leasehold and royalty interests of Chesapeake Energy Corporation (Chesapeake) in the Colony Granite Wash Field as of June 30, 2011. It is our understanding that the
proved reserves estimated in this report constitute approximately 3.1 percent of all proved reserves owned by Chesapeake. The subject properties are located in the State
of Oklahoma. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange
Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009, in the Federal
Register (SEC regulations). Our third party study, completed on July 22, 2011, and presented herein, was prepared for public disclosure by Chesapeake in filings made
with the SEC pursuant to the Securities Act of 1933, as amended.
The estimated reserves and future net income amounts presented in this report, as of June 30, 2011, are related to hydrocarbon prices. The hydrocarbon prices
used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined
as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual
arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of
reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of
this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Attributable to Certain interests of
Chesapeake Energy Corporation
Colony Granite Wash Field
As of June 30, 2011
Proved
Developed
Producing
Net Remaining Reserves
Oil/Condensate—MBarrels
Plant Products—MBarrels
Gas—MMCF
Income Data (M$)
Future Gross Revenue
Deductions
Non-Producing
2,258
7,055
68,636
Total
Proved
Undeveloped
390
736
7,053
8,290
18,640
179,931
10,938
26,431
255,620
$
634,122
52,023
$
79,672
12,292
$
1,901,165
626,687
$
2,614,959
691,002
Future Net Income (FNI)
$
582,099
$
67,380
$
1,274,478
$
1,923,957
Discounted FNI @ 10%
$
308,228
$
35,276
$
510,087
$
853,591
600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4
621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501
TEL (403) 262-2799
TEL (303) 623-9147
A-2
FAX (403) 262-2790
FAX (303) 623-4258
Table of Contents
Index to Financial Statements
Chesapeake Energy Corporation
August 10, 2011
Page 2
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in
millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions,
and income data are expressed as thousands of U.S. dollars (M$).
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries TM
System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of Chesapeake. Ryder Scott has found
this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the
properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also
due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, development costs,
and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and
has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves
account for approximately 72.7 percent and gas reserves account for the remaining 27.3 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
Discounted Future Net Income (M$)
As of June 30, 2011
Discount Rate
Percent
Total Proved
5
8
12
14
$
$
$
$
1,190,438
963,942
764,562
691,153
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An
abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed
non-producing reserves included herein consist of the shut-in category.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein
do not attribute gas consumed in operations as reserves.
RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
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Chesapeake Energy Corporation
August 10, 2011
Page 3
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining
quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount
of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by
placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may
be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Chesapeake’s request, this report
addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty
to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are
used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For
proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data
are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover,
estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore,
the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the
actual costs related thereto, could be more or less than the estimated amounts.
Chesapeake’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be
limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing
and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and
policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Chesapeake owns an interest; however, we have
not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs
included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and
the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the
Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of
certain generally accepted analytical procedures. These
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PETROLEUM CONSULTANTS
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Chesapeake Energy Corporation
August 10, 2011
Page 4
analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may
be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or
combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at
the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity
of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible
outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the
uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the
uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of
reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is
defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable
reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be
recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities
ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve
category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become
available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic
conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods .
The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through early June 2011 in those
cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Chesapeake or obtained from public data
sources and were considered sufficient for the purpose thereof. Methods other than performance were used where there were inadequate historical performance data to
establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Proved reserves for 100 percent of the undeveloped locations were determined by analogy to direct offset production and supported by appropriate isochore
mapping.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but
not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on
current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be
anticipated to be economically producible from a given
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PETROLEUM CONSULTANTS
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Chesapeake Energy Corporation
August 10, 2011
Page 5
date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may
reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or
decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this
evaluation.
Chesapeake has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data
required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Chesapeake with respect to
property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or
processing fees, production taxes, development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to
product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data furnished by Chesapeake. We consider the factual data used in this report
appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all
such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were
determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all
references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report
comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been
established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.
An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future
production rates.
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.
For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Chesapeake. Wells or locations that are not currently
producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such
factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory
bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because
of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or
operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
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Chesapeake Energy Corporation
August 10, 2011
Page 6
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the
period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period,
unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations,
exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic
average as previously described.
Chesapeake furnished us with the above mentioned average prices in effect on June 30, 2011. These initial SEC hydrocarbon prices were determined using the
12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the
adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the
report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity,
quality, local conditions, distance from market, and gathering fees, referred to herein as “differentials.” The differentials used in the preparation of this report were
furnished to us by Chesapeake. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not
conducted an independent verification of the data used by Chesapeake to determine these differentials
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized
prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for
the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
Geographic Area
United States
Product
Oil/Condensate
NGLs
Gas
Price Reference
WTI Cushing
WTI Cushing
Henry Hub—
Colorado Interstate
Average
Benchmark Prices
$89.86/Bbl
$89.86/Bbl
$4.209/MMBTU
Average
Realized Prices
$86.08/Bbl
$39.83/Bbl
$2.93/MCF
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report are based on the operating expense reports of Chesapeake and include only those costs directly applicable
to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the
operating costs include an appropriate level of corporate general administrative and overhead costs shown as
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Chesapeake Energy Corporation
August 10, 2011
Page 7
“Other Costs”. The operating costs furnished by Chesapeake were reviewed by us for their reasonableness using information furnished by Chesapeake for this purpose.
No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by Chesapeake and are based on authorizations for expenditure (AFEs) for the proposed work or actual costs for similar
projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an
independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were
significant. The estimates of the net abandonment costs furnished by Chesapeake were accepted without independent verification.
The proved undeveloped reserves in this report have been incorporated herein in accordance with Chesapeake’s plans to develop these reserves as of June 30,
2011. The implementation of Chesapeake’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Chesapeake’s
management. As the result of our inquiries during the course of preparing this report, Chesapeake has informed us that the development activities included herein have
been subjected to and received the internal approvals required by Chesapeake’s management at the appropriate local, regional and/or corporate level. In addition to the
internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or
other administrative approvals external to Chesapeake. Additionally, Chesapeake has informed us that they are not aware of any legal, regulatory, political or economic
obstacles that would significantly alter their plans.
Current costs were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over
seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or
job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and
independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each
engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations
and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and
enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a
registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate
governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to Chesapeake. Neither we nor any of our employees have any interest in the subject properties and neither
the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
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Chesapeake Energy Corporation
August 10, 2011
Page 8
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional
qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are
included as an attachment to this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC
regulations and intended for public disclosure as an exhibit in filings made with the SEC by Chesapeake.
We have provided Chesapeake with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital
version included in filings made by Chesapeake and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
/s/ Don. P. Griffin
Don P. Griffin, P.E.
TBPE License No. 64150
Senior Vice President
[SEAL]
DPG/sm
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P.
Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.
Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and
consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering
positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott
Company website at http://www.ryderscott.com/Experience/Employees.php .
Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional
Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of
continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. As part of his 2009 continuing education hours,
Mr. Griffin attended an internally presented 16 hours of formalized training relating to the definitions and disclosure guidelines contained in the United States Securities
and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal
Register. Mr. Griffin attended an additional 15 hours of training during 2010 covering such topics as reservoir engineering, geoscience and petroleum economics
evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves,
Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the
Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and
additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and
codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation
S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and
Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations,
Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in
italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining
quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount
of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by
placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be
further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of
December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly
filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such
resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202
Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding,
thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as
petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or
unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional
petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These
unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
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Petroleum Reserves Definitions
Page 2
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by
application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right
to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to
implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated
and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive
reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable
resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating
methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the
operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or
gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless
geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher
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Index to Financial Statements
portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in
the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on
which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price
during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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Petroleum Reserves Definitions
Page 3
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
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Index to Financial Statements
RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal
Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents
(direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a
new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance
contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1)
completion intervals which are open at the time of the estimate, but which have not started producing;
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RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
(2)
wells which were shut-in for market conditions or pipeline connections; or
(3)
wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start
of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled,
unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled
within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined
in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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Chesapeake Granite Wash Trust
Estimated
Future Reserves and Income
Attributable to Certain Interests in
Colony Granite Wash Field
SEC Parameters
As of
June 30, 2011
\s\ Don P. Griffin
Don P. Griffin, P.E.
TBPE License No. 64150
Senior Vice President
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY
PETROLEUM CONSULTANTS
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TBPE REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA
SUITE 3800
FAX (713) 651-0849
TELEPHONE (713) 651-9191
HOUSTON, TEXAS 77002-5235
August 10, 2011
Chesapeake Granite Wash Trust
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Gentlemen:
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain
royalty interests that will be conveyed to Chesapeake Granite Wash Trust (Trust) by Chesapeake Energy Corporation in the Colony Granite Wash Field as of June 30,
2011. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves that will be conveyed to and owned by the Trust. The
subject properties are located in the State of Oklahoma. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United
States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released
January 14, 2009, in the Federal Register (SEC regulations). Our third party study, completed on July 22, 2011, and presented herein, was prepared for public disclosure
by Chesapeake in filings made with the SEC pursuant to the Securities Act of 1933, as amended.
The estimated reserves and future net income amounts presented in this report, as of June 30, 2011, are related to hydrocarbon prices. The hydrocarbon prices
used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined
as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual
arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of
reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of
this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Attributable to Certain interests of
Chesapeake Granite Wash Trust
Colony Granite Wash Field
As of June 30, 2011
Proved
Total
Proved
Developed
Producing
Net Remaining Reserves
Oil/Condensate – MBarrels
Plant Products – MBarrels
Gas – MMCF
Income Data (M$)
Future Gross Revenue
Deductions (1)
Non-Producing
1,902
5,644
54,878
Undeveloped
331
591
5,658
4,002
8,319
80,325
6,235
14,554
140,861
$
511,462
—
$
65,244
—
$
871,267
—
$
1,447,973
—
Future Net Income (FNI)
$
511,462
$
65,244
$
871,267
$
1,447,973
Discounted FNI @ 10%
$
285,866
$
39,568
$
485,706
$
811,140
(1)
FNI has been calculated without deduction for production and development costs, as the Trust will not bear those costs.
600, 1015 4TH STREET, S.W.
621 17TH STREET, SUITE 1550
CALGARY, ALBERTA T2R 1J4
DENVER, COLORADO 80293-1501
A-17
TEL (403) 262-2799
TEL (303) 623-9147
FAX (403) 262-2790
FAX (303) 623-4258
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Chesapeake Granite Wash Trust
August 10, 2011
Page 2
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in
millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions,
and income data are expressed as thousands of U.S. dollars (M$).
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries TM
System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of Chesapeake Energy Corporation
(Chesapeake). Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not
exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections
of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, development costs,
and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and
has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves
account for approximately 73.4 percent and gas reserves account for the remaining 26.6 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
Discounted Future Net Income (M$)
As of June 30, 2011
Discount Rate
Percent
Total Proved
5
8
12
14
$
$
$
$
1,028,325
884,537
750,116
698,474
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An
abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed
non-producing reserves included herein consist of the shut-in category.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein
do not attribute gas consumed in operations as reserves.
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August 10, 2011
Page 3
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining
quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount
of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by
placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may
be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Chesapeake’s request, this report
addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty
to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are
used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For
proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data
are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover,
estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore,
the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the
actual costs related thereto, could be more or less than the estimated amounts.
Chesapeake’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be
limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing
and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and
policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Chesapeake owns an interest; however, we have
not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs
included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and
the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the
Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of
certain generally accepted analytical procedures. These
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analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may
be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or
combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at
the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity
of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible
outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the
uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the
uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of
reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is
defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable
reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be
recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities
ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve
category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become
available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic
conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods .
The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through early June 2011 in those
cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Chesapeake or obtained from public data
sources and were considered sufficient for the purpose thereof. Methods other than performance were used where there were inadequate historical performance data to
establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
Proved reserves for 100 percent of the undeveloped locations were determined by analogy to direct offset production and supported by appropriate isochore
mapping.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but
not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on
current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be
anticipated to be economically producible from a given
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date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may
reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or
decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this
evaluation.
Chesapeake has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data
required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Chesapeake with respect to
property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or
processing fees, production taxes, development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to
product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data furnished by Chesapeake. We consider the factual data used in this report
appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all
such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were
determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all
references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report
comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been
established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.
An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future
production rates.
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.
For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Chesapeake. Wells or locations that are not currently
producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such
factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory
bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because
of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or
operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
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Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the
period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period,
unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations,
exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic
average as previously described.
Chesapeake furnished us with the above mentioned average prices in effect on June 30, 2011. These initial SEC hydrocarbon prices were determined using the
12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the
adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the
report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity,
quality, local conditions, distance from market, and gathering fees, referred to herein as “differentials.” The differentials used in the preparation of this report were
furnished to us by Chesapeake. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not
conducted an independent verification of the data used by Chesapeake to determine these differentials
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized
prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for
the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
Geographic Area
United States
Product
Oil/Condensate
NGLs
Gas
Price Reference
WTI Cushing
WTI Cushing
Henry Hub—Colorado Interstate
Average
Benchmark Prices
$89.86/Bbl
$89.86/Bbl
$4.209/MMBTU
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
The Trust bears no burden for costs other than gathering fees which have been included in this report as a price differential.
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Average
Realized Prices
$86.09/Bbl
$39.80/Bbl
$2.86/MCF
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Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over
seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or
job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and
independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each
engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations
and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and
enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a
registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate
governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to the Trust and Chesapeake. Neither we nor any of our employees have any interest in the subject
properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional
qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are
included as an attachment to this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC
regulations and intended for public disclosure as an exhibit in filings made with the SEC by Chesapeake.
We have provided the Trust with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital
version included in filings made by the Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.
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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
\s\ Don P. Griffin
Don P. Griffin, P.E.
TBPE License No. 64150
Senior Vice President
[SEAL]
DPG/sm
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P.
Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.
Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and
consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering
positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott
Company website at http://www.ryderscott.com/Experience/Employees.php .
Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional
Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of
continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. As part of his 2009 continuing education hours,
Mr. Griffin attended an internally presented 16 hours of formalized training relating to the definitions and disclosure guidelines contained in the United States Securities
and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal
Register. Mr. Griffin attended an additional 15 hours of training during 2010 covering such topics as reservoir engineering, geoscience and petroleum economics
evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves,
Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the
Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and
additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and
codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation
S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and
Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations,
Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in
italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining
quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount
of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by
placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be
further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of
December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly
filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such
resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202
Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding,
thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as
petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or
unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional
petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These
unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
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Page 2
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by
application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right
to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to
implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated
and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive
reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable
resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating
methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the
operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or
gas on the basis of available geoscience and engineering data.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless
geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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Page 3
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish
the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in
the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on
which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price
during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal
Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents
(direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a
new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance
contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
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RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1)
completion intervals which are open at the time of the estimate, but which have not started producing;
(2)
wells which were shut-in for market conditions or pipeline connections; or
(3)
wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start
of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled,
unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled
within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined
in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
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Annex B
Chesapeake Granite Wash Trust
Quarterly Target Distributions
Quarter Ending
30-Sep-11
31-Dec-11
31-Mar-12
30-Jun-12
30-Sep-12
31-Dec-12
31-Mar-13
30-Jun-13
30-Sep-13
31-Dec-13
31-Mar-14
30-Jun-14
30-Sep-14
31-Dec-14
31-Mar-15
30-Jun-15
30-Sep-15
31-Dec-15
31-Mar-16
30-Jun-16
30-Sep-16
31-Dec-16
31-Mar-17
30-Jun-17
30-Sep-17
31-Dec-17
31-Mar-18
30-Jun-18
30-Sep-18
31-Dec-18
31-Mar-19
30-Jun-19
30-Sep-19
31-Dec-19
31-Mar-20
30-Jun-20
30-Sep-20
31-Dec-20
31-Mar-21
30-Jun-21
(1)
(2)
Subordination
Threshold (1)
Target
Distribution
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.37
0.56
0.59
0.61
0.63
0.68
0.70
0.70
0.72
0.70
0.70
0.69
0.70
0.67
0.67
0.69
0.65
0.56
0.51
0.47
0.44
0.42
0.39
0.38
Incentive
Threshold
(1)
0.46
0.70
0.74
0.76
0.79
0.85
0.87
0.87
0.90
0.88
0.88
0.86
0.87
0.84
0.84
0.86
0.81
0.70
0.64
0.59
0.55
0.52
0.49
0.47
0.45
0.43
0.42
0.40
0.39
0.38
0.37
0.36
0.35
0.34
0.33
0.32
0.32
0.31
0.31
0.30
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.55
0.85
0.89
0.91
0.95
1.02
1.05
1.05
1.08
1.05
1.06
1.04
1.05
1.00
1.00
1.03
0.97
0.84
0.77
0.71
0.66
0.62
0.59
0.56
Quarter Ending
30-Sep-21
31-Dec-21
31-Mar-22
30-Jun-22
30-Sep-22
31-Dec-22
31-Mar-23
30-Jun-23
30-Sep-23
31-Dec-23
31-Mar-24
30-Jun-24
30-Sep-24
31-Dec-24
31-Mar-25
30-Jun-25
30-Sep-25
31-Dec-25
31-Mar-26
30-Jun-26
30-Sep-26
31-Dec-26
31-Mar-27
30-Jun-27
30-Sep-27
31-Dec-27
31-Mar-28
30-Jun-28
30-Sep-28
31-Dec-28
31-Mar-29
30-Jun-29
30-Sep-29
31-Dec-29
31-Mar-30
30-Jun-30
30-Sep-30
31-Dec-30
31-Mar-31
30-Jun-31
Remaining(2)
Target
Distribution
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.30
0.29
0.29
0.28
0.28
0.27
0.27
0.27
0.26
0.26
0.26
0.25
0.25
0.25
0.24
0.24
0.24
0.23
0.23
0.23
0.23
0.22
0.22
0.21
0.21
0.21
0.20
0.20
0.20
0.20
0.19
0.19
0.18
0.18
0.18
0.17
0.17
0.17
0.17
0.16
2.23
For each quarter, the Subordination Threshold equals 80% of the Target Distribution, and the Incentive Threshold equals 120% of the Target Distribution.
Remaining includes proceeds attributable to one month of production for June 2031 and proceeds from the sale of the remaining reserves subject to the Perpetual Royalties calculated as
described under “Target Distributions and Subordination and Incentive Thresholds—Significant Assumptions Used to Calculate the Target Distributions—Valuation of Perpetual Royalties” on
page 60.
B-1
Table of Contents
Index to Financial Statements
Until
, 2011 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the common units, whether
or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
22,875,000 Common Units
Chesapeake Granite Wash Trust
PROSPECTUS
MORGAN STANLEY
Deutsche Bank Securities
RAYMOND JAMES
Goldman, Sachs & Co.
, 2011
Wells Fargo Securities
Table of Contents
Index to Financial Statements
PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
Items 13/14.
Other Expenses of Issuance and Distribution.
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of
the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are
estimates.
SEC registration fee
FINRA filing fee
NYSE listing fee
Printing and engraving expenses
Fees and expenses of legal counsel
Accounting fees and expenses
Transfer agent and registrar fees
Trustee fees and expenses
$
67,759
$
58,863
$ 206,800
$ 400,000
$ 1,425,000
$ 400,000
$
3,500
$
10,000
Total
Items 14/15.
$ 2,571,922
Indemnification of Directors and Officers.
The trust agreement provides that each of the trustee and the Delaware trustee and their respective officers, agents and employees shall be indemnified from the
assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by them as trustee or Delaware trustee in the administration of the
trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under
environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or Delaware trustee or acting in such capacity,
except such liability, expense, claims, damages or loss as to which each is liable under the trust agreement. In this regard, the trustee and Delaware trustee shall be liable
only for willful misconduct or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any of their respective agents or
employees unless the trustee or Delaware trustee, as applicable, has acted in bad faith, willful misconduct or with gross negligence in the selection and retention of such
agent or employee. Each of the trustee and the Delaware trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to
secure for each the foregoing indemnification.
Section 1031 of the Oklahoma General Corporation Act, under which Chesapeake is incorporated, authorizes the indemnification of directors and officers under
certain circumstances. Article VIII of the Certificate of Incorporation of Chesapeake and Article VI of the Amended and Restated Bylaws of Chesapeake also provide
for indemnification of directors and officers under certain circumstances. These provisions, together with Chesapeake’s indemnification obligations under individual
indemnity agreements with its directors and officers, may be sufficiently broad to indemnify such persons for liabilities under the Securities Act of 1933 (the “Securities
Act”), as amended. In addition, Chesapeake maintains insurance, which insures its directors and officers against certain liabilities.
The Oklahoma General Corporation Act provides for indemnification of each of Chesapeake’s officers and directors against (a) expenses, including attorneys’
fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by them in connection with any action, suit or proceeding brought by reason of
such person being or having been a director, officer, employee or agent of Chesapeake, or of any other corporation, partnership, joint venture, trust or other enterprise at
the request of Chesapeake, other than an action by or in the right of Chesapeake. To be entitled to indemnification, the individual must have acted in good faith and in a
manner he reasonably believed to be in or not opposed to the best interest of Chesapeake, and with respect to any
II-1
Table of Contents
Index to Financial Statements
criminal action, the person seeking indemnification had no reasonable cause to believe that the conduct was unlawful and (b) expenses, including attorneys’ fees,
actually and reasonably incurred in connection with the defense or settlement of any action or suit by or in the right of Chesapeake brought by reason of the person
seeking indemnification being or having been a director, officer, employee or agent of Chesapeake, or any other corporation, partnership, joint venture, trust or other
enterprise at the request of Chesapeake, provided the actions were in good faith and were reasonably believed to be in or not opposed to the best interest of Chesapeake,
except that no indemnification shall be made in respect of any claim, issue or matter as to which the individual shall have been adjudged liable to Chesapeake, unless
and only to the extent that the court in which such action was decided has determined that the person is fairly and reasonably entitled to indemnity for such expenses
which the court deems proper. Article VIII of Chesapeake’s Certificate of Incorporation provides for indemnification of Chesapeake’s directors and officers. The
Oklahoma General Corporation Act also permits Chesapeake to purchase and maintain insurance on behalf of Chesapeake’s directors and officers against any liability
arising out of their status as such, whether or not Chesapeake would have the power to indemnify them against such liability. These provisions may be sufficiently
broad to indemnify such persons for liabilities arising under the Securities Act.
Chesapeake has entered into indemnity agreements with each of its directors and executive officers. Under each indemnity agreement, Chesapeake will pay on
behalf of the indemnitee any amount which he is or becomes legally obligated to pay because of (a) any claim or claims from time to time threatened or made against
him by any person because of any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he
commits or suffers while acting in his capacity as a director and/or officer of Chesapeake or an affiliate or (b) being a party, or being threatened to be made a party, to
any threatened, pending or contemplated action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was an
officer, director, employee or agent of Chesapeake or an affiliate or is or was serving at the request of Chesapeake as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other enterprise. The payments which Chesapeake would be obligated to make under an indemnification agreement could
include damages, charges, judgments, fines, penalties, settlements and costs, cost of investigation and cost of defense of legal, equitable or criminal actions, claims or
proceedings and appeals therefrom, and costs of attachment, supersedeas, bail, surety or other bonds. Chesapeake also provides liability insurance for each of its
directors and executive officers.
The above discussion of Chesapeake’s Certificate of Incorporation and Amended and Restated Bylaws and Section 1031 of the Oklahoma General Corporation
Act is not intended to be exhaustive and is respectively qualified in its entirety by reference to Chesapeake’s Certificate of Incorporation and Amended and Restated
Bylaws and the Oklahoma General Corporation Act.
Item 15.
Recent Sales of Unregistered Securities.
None.
II-2
Table of Contents
Index to Financial Statements
Item 16.
Exhibits and Financial Statement Schedules.
The following documents are filed as exhibits to this registration statement:
Exhibit
Number
Description
1.1
Form of Underwriting Agreement
3.1†
Certificate of Trust of Chesapeake Granite Wash Trust
4.1†
Trust Agreement of Chesapeake Granite Wash Trust, dated June 29, 2011
4.2†
Form of Amended and Restated Trust Agreement of Chesapeake Granite Wash Trust
5.1
Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units to be registered under this Registration Statement
5.2
Opinion of Bracewell & Giuliani LLP relating to authorization of Chesapeake Granite Wash Trust
8.1
Opinion of Bracewell & Giuliani LLP relating to tax matters
10.1†
Form of Term Overriding Royalty Interest Conveyance (PDP)
10.2†
Form of Term Overriding Royalty Interest Conveyance (PUD)
10.3†
Form of Perpetual Overriding Royalty Interest Conveyance (PDP)
10.4†
Form of Perpetual Overriding Royalty Interest Conveyance (PUD)
10.5†
Form of Assignment of Royalty Interest
10.6†
Form of Administrative Services Agreement
10.7†
Form of Development Agreement
10.8
10.9†
10.10†
Form of Drilling Support Mortgage
Form of Registration Rights Agreement
23.1
Consent of PricewaterhouseCoopers LLP
23.2
Consent of Ryder Scott Company, L.P.
23.3†
Consent of Netherland, Sewell & Associates, Inc.
23.4†
Consent of Data & Consulting Services, Division of Schlumberger Technology Corporation
23.5†
Consent of Lee Keeling and Associates, Inc.
23.6
Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1)
23.7
Consent of Bracewell & Giuliani LLP (contained in Exhibit 8.1)
24.1†
99.1
†
Item 17.
Form of Hedge Contract
Powers of Attorney (included on signature pages of original Registration Statement)
Summary Reserve Reports of Ryder Scott Company, L.P. (included as Annex A to the prospectus)
Previously filed
Undertakings.
The undersigned registrants hereby undertake that, for purposes of determining any liability under the Securities Act of 1933, each filing of a registrant’s annual
report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report
pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration
statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
The undersigned registrants hereby undertake to provide to the underwriters at the closing specified in the underwriting agreement certificates in such
denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
II-3
Table of Contents
Index to Financial Statements
The undersigned registrants hereby undertake that:
(1)
For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrants pursuant to Rule 424(b)(1) or (4) or
497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2)
For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus
shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of the registrants
pursuant to the foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense
of any action, suit, or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless
in the opinion of their respective counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such
indemnification by them is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.
II-4
Table of Contents
Index to Financial Statements
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Chesapeake Granite Wash Trust has duly caused this Registration Statement to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on October 18, 2011.
Chesapeake Granite Wash Trust
By: CHESAPEAKE ENERGY CORPORATION
By
/s/ JENNIFER M. GRIGSBY
Name:
Title:
Jennifer M. Grigsby
Senior Vice President, Treasurer and Corporate
Secretary
II-5
Table of Contents
Index to Financial Statements
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Chesapeake Energy Corporation certifies that it has reasonable grounds to believe that it meets all of
the requirements for filing on Form S-3 and has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Oklahoma City, State of Oklahoma, on October 18, 2011.
Chesapeake Energy Corporation
By
Name:
Title:
/s/ AUBREY K. MCCLENDON
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
II-6
Table of Contents
Index to Financial Statements
Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the
dates indicated.
Signature
/s/ AUBREY K. MCCLENDON
Aubrey K. McClendon
/s/ DOMENIC J. DELL’OSSO, JR.
Domenic J. Dell’Osso, Jr.
/s/ MICHAEL A. JOHNSON
Michael A. Johnson
*
Title
Date
Chairman of the Board, Chief Executive Officer and
Director (Principal Executive Officer)
October 18, 2011
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
October 18, 2011
Senior Vice President—Accounting, Controller and Chief
Accounting Officer (Principal Accounting Officer)
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Director
October 18, 2011
Richard K. Davidson
*
Kathleen Eisbrenner
*
V. Burns Hargis
*
Frank Keating
*
Charles T. Maxwell
*
Merrill A. Miller, Jr.
*
Don Nickles
*
Louis A. Simpson
*By:
/s/ AUBREY K. MCCLENDON
Aubrey K. McClendon
Attorney-in-fact
II-7
Exhibit 1.1
[22,875,000] COMMON UNITS
CHESAPEAKE GRANITE WASH TRUST
CHESAPEAKE ENERGY CORPORATION
COMMON UNITS REPRESENTING BENEFICIAL INTERESTS
UNDERWRITING AGREEMENT
, 2011
[22,875,000] Common Units
CHESAPEAKE GRANITE WASH TRUST
CHESAPEAKE ENERGY CORPORATION
UNDERWRITING AGREEMENT
[
], 2011
Morgan Stanley & Co. LLC
Raymond James & Associates, Inc.
As Representatives of the several underwriters
named in Schedule 1 attached hereto
c/o Morgan Stanley & Co. LLC
1585 Broadway
New York, New York 10036
c/o Raymond James & Associates, Inc.
880 Carillon Parkway
St. Petersburg, Florida 33716
Ladies and Gentlemen:
Chesapeake Granite Wash Trust, a statutory trust formed under the laws of the State of Delaware (the “Trust”), proposes, subject to the terms and conditions
stated herein, to issue and sell to the several Underwriters named in Schedule I hereto (the “ Underwriters ”), an aggregate of [22,875,000] common units
representing beneficial interest in the Trust (the “ Common Units ”). The aggregate of [22,875,000] Common Units to be purchased from the Trust are referred to in this
Agreement as the “ Firm Units .” The Trust also proposes to issue and sell to the several Underwriters not more than [3,431,250] additional Common Units (the “
Additional Units ”) if and to the extent that the Underwriters shall determine to exercise the right to purchase such Additional Units granted to the Underwriters in
Section 2 hereof. The Firm Units and the Additional Units are collectively referred to in this Agreement as the “ Units .” Morgan Stanley & Co. LLC (“ Morgan
Stanley ”) and Raymond James & Associates, Inc. are acting as the representatives of the several Underwriters and in such capacity are referred to in this Agreement as
the “ Representatives .”
It is understood and agreed by all parties hereto that Chesapeake Energy Corporation, an Oklahoma corporation (the “Company”), has caused the formation of
the Trust and will convey, or cause to be conveyed, to the Trust (a) overriding royalty interests entitling the Trust to receive 90% of the proceeds (after deducting certain
post-production expenses) from the sale of production of oil, natural gas liquids and natural gas attributable to the Company’s net revenue interest in certain horizontal
wells (the “ Producing Wells ”) producing from the Colony Granite Wash play located in Washita County in Oklahoma (the “ PDP Royalty Interest ”) and (b)
overriding royalty interests entitling the Trust to receive 50% of the proceeds (after deducting certain post-production expenses) from the sale of production of oil,
natural gas liquids and natural gas attributable to the Company’s net revenue interest in certain horizontal development wells (the “ Development Wells ”) to be drilled
exclusively in the Colony Granite Wash play on properties within a specified area of mutual interest (as such area may be extended pursuant to the Development
Agreement (as defined below), the “ AMI , ” and such royalty interests, the “ Development Royalty Interest ”) in exchange for, in the aggregate, (i) the net proceeds
from the public offering of the Firm Units contemplated hereby, (ii) 11,437,500 Common Units (which includes the Additional Units to be retained by the Trust
pursuant to Section 2 of this Agreement), (iii) 11,437,500] subordinated units representing beneficial interests in the Trust (the “ Subordinated Units ,” and together
with the Common Units, the “ Trust Units ”) and (iv) the right to receive Incentive Distributions, as such term is defined in the Trust Agreement (as defined below) (the
“ Incentive Distribution Rights ”). The Trust Units to be received by the Company or its designee from the Trust, including the Additional Units retained by the Trust
pursuant to Section 2 of this Agreement, are referred to herein as the “ Sponsor Units .” As used herein, the term “ Underlying Properties ” means those properties
owned by the Company from which the Company will convey, or cause the conveyance of, the PDP Royalty Interest and the Development Royalty Interest to the Trust.
It is further understood and agreed to by all parties hereto that the following transactions have occurred or will occur on or before the Initial Closing Date (as
defined below):
(a) The Company will cause Chesapeake Exploration L.L.C., an Oklahoma limited liability company and an indirect wholly owned subsidiary of the Company
(“ Chesapeake Exploration ”), to convey to Chesapeake E&P Holding Corporation, an Oklahoma corporation and an indirect wholly owned subsidiary of the Company
(the “ Assignee ” and together with the Company and Chesapeake Exploration, the “ Chesapeake Entities ”), (i) pursuant to a Term Overriding Royalty Interest
Conveyance (PDP) (the “ PDP Term Conveyance ”), a term overriding royalty interest entitling the holder of the interest to receive 45% of the proceeds from the sale
of production of oil, natural gas liquids and natural gas attributable to Chesapeake Exploration’s net revenue interest in the Producing Wells (after deducting Chargeable
Costs (as defined in the PDP Term Conveyance)) for a period of 20 years commencing on July 1, 2011 (the “ Term PDP Royalty ”) and (ii) pursuant to a Term
Overriding Royalty Interest Conveyance (PUD) (the “ PUD Term Conveyance ”, and together with the PDP Term Conveyance, the “ Term Conveyances ”), a term
overriding royalty interest entitling such holder of the interest to receive 25% of the proceeds from the sale of the production of oil, natural gas liquids and natural gas
attributable to Chesapeake Exploration’s net revenue interest in the Development Wells (after deducting Chargeable Costs (as defined in the PUD Term Conveyance))
for a period of 20 years commencing on July 1, 2011 (the “ Term PUD Royalty ” and, together with the Term PDP Royalty, the “ Term Royalties ”). The consideration
provided by Assignee to Chesapeake Exploration in respect of the Term Royalties shall be a demand note in the principal amount of approximately $[
] million
(the “ Demand Note ”).
(b) The Company will cause Chesapeake Exploration to convey to the Trust, (i) pursuant to a Perpetual Overriding Royalty Interest Conveyance (PDP) (the “
PDP Perpetual Conveyance ”), a perpetual overriding royalty interest entitling the Trust to receive 45% of the
3
proceeds from the sale of oil, natural gas liquids and natural gas production attributable to Chesapeake Exploration’s net revenue interest in the Producing Wells (after
deducting Chargeable Costs (as defined in the PDP Perpetual Conveyance)) (the “ Perpetual PDP Royalty ”) and (ii) pursuant to a Perpetual Overriding Royalty
Conveyance (PUD) (the “ PUD Perpetual Conveyance ”, and together with the PDP Perpetual Conveyance, the “ Perpetual Conveyances ”), a perpetual overriding
royalty interest entitling the Trust to receive 25% of the proceeds from the sale of production of oil, natural gas liquids and natural gas attributable to Chesapeake
Exploration’s net revenue interest in the Development Wells (after deducting Chargeable Costs (as defined in the PUD Perpetual Conveyance)) (the “ Perpetual PUD
Royalty ” and, together with the Perpetual PDP Royalty, the “ Perpetual Royalties ”). The consideration provided by the Trust to Chesapeake Exploration in respect of
the Perpetual Royalties shall be (i) the Sponsor Units, (ii) the net proceeds from the public offering of the Firm Units in excess of the principal amount of the Demand
Note, and (iii) the Incentive Distribution Rights.
(c) Pursuant to that certain Assignment of Term Overriding Royalty Interests (the “Assignment and Conveyance” and, together with the Term Conveyances and
the Perpetual Conveyances and any related bills of sale, conveyances and similar documents in connection therewith, the “ Conveyance Documents ”) by and between
Assignee and the Trust, Assignee will assign the Term Royalties to the Trust in exchange for an amount equal to the principal amount of the Demand Note, which shall
be paid from the net proceeds from this offering (assuming no exercise of the right to purchase Additional Units granted to the Underwriters in Section 2 hereof).
Assignee will use such proceeds to repay the Demand Note to Chesapeake Exploration.
(d) The public offering of the Firm Units contemplated hereby will be consummated;
(e) The Trust Agreement of the Trust by and among the Company, The Bank of New York Mellon Trust Company, N.A., as trustee (the “ Trustee ”), and The
Corporation Trust Company, as Delaware trustee (the “ Delaware Trustee ”), as amended to the date hereof (the “ Organizational Trust Agreement ”), shall be
amended and restated (as so amended and restated, the “ Trust Agreement ”).
(f) The Company will novate and assign to the Trust certain hedging arrangements and the Trust will enter into such hedging arrangements and pledge certain
collateral thereunder (the agreements, instruments, mortgage and other documents relating thereto, the “ Hedge Documentation ”), in each case on terms described in
the Registration Statement, the Prospectus and the Time of Sale Information (each as defined below).
(g) The Company and the Trust will enter into an Administrative Services Agreement outlining the provision of administrative services to the Trust by the
Company and its compensation therefor (the “ Administrative Services Agreement ”).
(h) The Company, Chesapeake Exploration and the Trust will enter into a Development Agreement outlining the Company’s drilling and other obligations to the
Trust with respect to the Development Wells (the “ Development Agreement ”).
4
(i) Chesapeake Exploration will execute a mortgage and grant to the Trust a mortgage lien and security interest on Chesapeake Exploration’s interest in
the AMI (except the Producing Wells and any other wells which are not subject to the Royalty Interests) (the “ Drilling Support Mortgage ”, and together with
all UCC-1 Financing Statements and other documentation in connection with and necessary to perfect the Drilling Support Mortgage, the “ Mortgage
Documentation ”) in order to secure the Company’s and Chesapeake Exploration’s drilling obligation under the Development Agreement.
(j) The Trust will enter into a registration rights agreement with the Company and Chesapeake Exploration relating to the Sponsor Units (the “ Registration
Rights Agreement ”).
(k) If the Underwriters exercise their right to purchase Additional Units from the Trust in accordance with Section 2 hereof, the Trust will deliver the net
proceeds of such sale plus any Additional Units not purchased by the Underwriters pursuant to this Agreement to the Company as partial consideration for the
conveyance of the Perpetual Royalties.
The transactions contemplated above are referred to herein as the “Transactions.”
The “Conveyances” shall mean the Term Conveyances and the Perpetual Conveyances.
The “Transaction Documents” shall mean this Agreement, the Conveyance Documents, the Mortgage Documentation, the Administrative Services Agreement,
the Development Agreement, the Hedge Documentation, the Demand Note and the Registration Rights Agreement.
The “Organizational Documents” shall mean the Organizational Trust Agreement, the Trust Agreement, the Certificate of Trust of the Trust filed with the
Delaware Secretary of State on June 29, 2011 (the “ Certificate of Trust ”), the Restated Certificate of Incorporation and Amended and Restated Bylaws of the
Company, the Articles of Organization and the Second Amended and Restated Operating Agreement of Chesapeake Exploration and the Certificate of Incorporation
and the Bylaws of Assignee.
The “Operative Agreements” shall mean the Transaction Documents, the Organizational Trust Agreement and the Trust Agreement.
1. Representations and Warranties.
1.1 Of the Company and the Trust. The Company and the Trust hereby jointly and severally represent and warrant to, and agree with, each Underwriter on the
date hereof, and shall be deemed to jointly and severally represent and warrant to each Underwriter on each Closing Date, that (provided that the representations and
warranties in Section 1.1(cc), (ee) and (gg), solely to the extent such representations and warranties relate to the trustee of the Trust, are made solely by the Trust):
(a) Registration Statement. The Trust and the Company have prepared and filed with the Securities and Exchange Commission (the “ Commission ”) in
accordance with the provisions of the Securities Act of 1933, as amended, and the rules and regulations of the Commission
5
thereunder (collectively, the “Securities Act”), a joint registration statement on Forms S-1 and S-3 (File Nos. 333-175395 and 333-175395-01), including a prospectus
subject to completion, relating to the Units. The joint Registration Statement on Forms S-1 and S-3 of the Trust and the Company (File Nos. 333-175395 and
333-175395-01), as amended, including the financial statements, exhibits, annexes and schedules thereto, at the initial Effective Date and as thereafter amended by any
post-effective amendment, is referred to in this Agreement as the “ Registration Statement .” For purposes of this Agreement:
(i) If the Trust and the Company have filed another registration statement with the Commission to register additional Common Units to be included in the
Units pursuant to Rule 462(b) under the Securities Act (the “ Rule 462 Registration Statement ”), then any reference to “ Registration Statement ” herein shall be
deemed to include the Rule 462 Registration Statement, as such registration statement may be amended pursuant to the Securities Act.
(ii) The prospectus subject to completion in the form included in the Registration Statement at the time of the initial filing of such Registration Statement with
the Commission and each such prospectus as amended from time to time until the date of the Prospectus is referred to in this Agreement as a “ Preliminary
Prospectus .”
(iii) The Preliminary Prospectus dated [
], 2011 relating to the Units that was included in the Registration Statement immediately prior to the Time of
Sale is referred to in this Agreement as the “ Pricing Prospectus .”
(iv) The final prospectus relating to the Units, in the form first filed pursuant to Rule 424(b) under the Securities Act, is referred to in this Agreement as the “
Prospectus .”
(v) The term “Free Writing Prospectus” shall have the meaning ascribed to it in Rule 405 under the Securities Act, and “ Issuer Free Writing Prospectus ”
shall mean each Free Writing Prospectus prepared by or on behalf of the Company or the Trust or used or referred to by the Company or the Trust in connection with
the offering of the Units.
(vi) The term “broadly available road show” shall mean a “bona fide electronic road show” as defined in Rule 433(h)(5) under the Securities Act that has
been made available without restriction to any person.
(vii) “Time of Sale Information” shall mean the Pricing Prospectus together with each Free Writing Prospectus, if any, identified in Schedule III hereto,
and the other information set out in Schedule III hereto.
(viii) “Effective Date” shall mean each date and time as of which any part of the Registration Statement became or is deemed to have become effective under
the Securities Act.
(ix) “Time of Sale” shall mean [
] p.m., New York, New York time, on the date of this Agreement.
6
All references in this Agreement to the Registration Statement, the Preliminary Prospectus, the Pricing Prospectus, the Prospectus or the Time of Sale
Information, or any amendments or supplements to any of the foregoing, shall be deemed to refer to and include any documents filed by the Company pursuant to the
Exchange Act (as defined below), and incorporated by reference therein (the “ Incorporated Documents ”), and shall include any copy thereof filed with the
Commission pursuant to its Electronic Data Gathering, Analysis and Retrieval System (“ EDGAR ”); provided, however, the Trust shall not be deemed to provide
any representation or warranty in this Agreement with respect to the Incorporated Documents.
(b) Effectiveness. The Registration Statement has become effective, no stop order suspending the effectiveness of the Registration Statement is in effect, and no
proceedings for such purpose are pending before or, to the knowledge of the Trust and the Company, threatened by the Commission. No order preventing or suspending
the use of any Preliminary Prospectus or Issuer Free Writing Prospectus has been issued and no proceeding has been initiated or, to the knowledge of the Trust and the
Company, threatened by the Commission.
(c) Compliance as to Form; No Material Misstatements or Omissions. The Registration Statement, at the initial Effective Date, the Time of Sale Information, at
the Time of Sale, and the Prospectus, at its date and when filed with the Commission, complied or will comply in all material respects with the applicable requirements
of the Securities Act. The Registration Statement, at the initial Effective Date, did not contain and, as amended or supplemented, if applicable, will not contain any
untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading. The Time of
Sale Information, at the Time of Sale, did not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements
therein, in the light of the circumstances under which they were made, not misleading. Each broadly available road show, if any, when considered together with the
Time of Sale Information, does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein, in
the light of the circumstances under which they were made, not misleading. The Prospectus, as of its date, will not contain, and as amended or supplemented, if
applicable, at each Closing Date, will not contain, any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements
therein, in the light of the circumstances under which they were made, not misleading. The representations and warranties set forth in this paragraph do not apply to
statements in or omissions from the Registration Statement, the Time of Sale Information or the Prospectus based upon information relating to any Underwriter
furnished to the Company or the Trust in writing by such Underwriter through you expressly for use therein, which information is specified in the last sentence of
Section 6(b) hereof.
(d) Trust Not an “Ineligible Issuer.” The Trust was not at the time of initial filing of the Registration Statement, is not on the date hereof and will not be on any
Closing Date an “ineligible issuer” (as defined in Rule 405 under the Securities Act).
(e) Free Writing Prospectus. Any Issuer Free Writing Prospectus that the Trust is required to file pursuant to Rule 433(d) under the Securities Act has been, or
will be, filed with the Commission in accordance with the requirements of the Securities Act and the applicable rules and regulations of the Commission thereunder.
Each Issuer Free Writing Prospectus that
7
the Trust has filed, or is required to file, pursuant to Rule 433(d) under the Securities Act or that was prepared by or on behalf of or used or referred to by the Trust
complies or will comply in all material respects with the requirements of the Securities Act. Except for the Free Writing Prospectuses, if any, identified in Schedule II
hereto, and electronic road shows, if any, each furnished to you before first use, the Trust has not prepared, used or referred to, or will not, without your prior consent,
prepare, use or refer to, any Free Writing Prospectus in connection with the offering of the Units.
(f) Exchange Act Registration Statement. The Trust has prepared and filed, in accordance with Section 12 of the Securities Exchange Act of 1934, as amended,
and the rules and regulations thereunder (collectively, the “ Exchange Act ”), a registration statement (as amended, the “ Exchange Act Registration Statement ”) on
Form 8-A (File No. 011-[ ]) under the Exchange Act to register, under Section 12(g) of the Exchange Act, the class of securities consisting of the Trust Units. The
Exchange Act Registration Statement has become effective as provided in Section 12 of the Exchange Act.
(g) Formation, Due Qualification and Authority of the Trust. The Trust has been duly formed and is validly existing as a statutory trust in good standing under
the Delaware Statutory Trust Act, 12 Del. C. § 3801 et seq. (the “ DST Act ”), and all filings required under the laws of the State of Delaware with respect to the
formation and valid existence of the Trust as a statutory trust have been made. The Trust has full power and authority to own or lease, as the case may be, its properties
and to conduct its business as described in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto) and
is duly registered and qualified to conduct its business and is in good standing in each jurisdiction or place where the nature of its properties or the conduct of its
business requires such registration or qualification, except where the failure to so register or qualify (i) has not had or would not be reasonably expected to have a
material adverse effect on the business, properties, financial condition, results of operations or prospects of the Trust or the Underlying Properties (a “ Material Adverse
Effect ”), (ii) has not materially impaired or would not be reasonably expected to materially impair the ability of the Trust or any of the Chesapeake Entities to
consummate the Transactions or any other transactions provided for in the Transaction Documents to which the Trust is a party or (iii) has not subjected or will not
subject the unitholders of the Trust to any material liability or disability. The activities of the Trustee pursuant to the Trust Agreement will not require the appointment
of an ancillary trustee in the State of Oklahoma.
(h) Outstanding Trust Units. At the Initial Closing Date, after giving effect to the Transactions, the Trust will have outstanding [45,750,000] Trust Units; such
Trust Units and the beneficial interests in the Trust represented thereby will be duly authorized and validly issued in accordance with the Trust Agreement, and will be
fully paid and nonassessable and free from any preemptive or similar rights.
(i) No Preemptive Rights, Registration Rights or Options. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus,
there are no options, warrants, preemptive rights or other rights issued or granted by the Trust to subscribe for or to purchase, nor any restriction (other than applicable
securities laws) upon the voting or transfer of, any Trust Securities (as defined herein). Neither the filing of the Registration Statement nor the offering or sale of any
Units as contemplated by this Agreement gives rise to any rights for or relating to the registration of any Trust Units or other securities of the Trust.
8
(j) Authority and Authorization. The Trust has all requisite power and authority to execute and deliver this Agreement and to perform its obligations
hereunder. The Trust has all requisite power and authority to issue, sell and deliver (i) the Trust Units, in accordance with and upon the terms and conditions set
forth in this Agreement and the Trust Agreement and as described in the Time of Sale Information and the Prospectus, and (ii) the Incentive Distribution Rights,
in accordance with the terms and conditions set forth in the Trust Agreement. At each Closing Date, all trust action required to be taken by the Trust or any of its
unitholders or the Trustee or the Delaware Trustee for the authorization, issuance, sale and delivery of the Trust Units and the Incentive Distribution Rights, the
execution and delivery of the Operative Agreements to which the Trust is a party and the consummation by the Trust of the Transactions, shall have been validly
taken. Upon such issuance of the Trust Units, the holders of the Trust Units will be entitled to the benefits of the Trust Agreement.
(k) Authorization of Underwriting Agreement. This Agreement has been duly authorized by the Trust and validly executed and delivered by the Trust.
(l) Enforceability of Operative Agreements. At or before each Closing Date, each of the Operative Agreements to which the Trust is a party will have been duly
authorized, executed and delivered by the Trustee or the Delaware Trustee, on behalf of the Trust, and is a valid and legally binding agreement of the Trust, enforceable
against the Trust in accordance with each of its terms, except as such enforceability thereof may be limited by (i) bankruptcy, insolvency, fraudulent transfer,
reorganization, moratorium and similar laws relating to or affecting creditors’ rights generally and by general principles of equity (regardless of whether such
enforceability is considered in a proceeding in equity or at law) and (ii) public policy, any applicable law relating to fiduciary duties and indemnification and an implied
covenant of good faith and fair dealing.
(m) No Conflicts. None of (i) the offering, issuance or sale by the Trust of the Trust Units as described in the Registration Statement, the Time of Sale
Information and the Prospectus, (ii) the execution, delivery and performance by the Trust of the Operative Agreements to which the Trust is a party, and (iii) the
consummation by the Trust of the transactions contemplated by the Transaction Documents to which the Trust is a party (A) conflicts with or will conflict with or
constitutes or will constitute a violation or breach of, or a default under, the Organizational Trust Agreement, the Trust Agreement or the Certificate of Trust,
(B) conflicts with or will conflict with or constitutes or will constitute a breach or violation of, or a default (or an event which, with notice or lapse of time or both,
would constitute such a default) under, any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which the Trust is a party or by
which any of its properties may be bound, (C) violates or will violate any statute, law, regulation, ruling or any order, judgment, decree or injunction of any court or
governmental agency or body directed to the Trust or its properties in a proceeding to which it or its properties is a party or is bound or (D) results or will result in the
creation or imposition of any liens, encumbrances, security interests, charges or other claims (each, a “ Lien ”) upon any property or assets of the Trust, except with
respect to clauses (B) - (D) for such conflicts, violations, breaches, defaults or Liens that have not had and will not have, individually or in the aggregate, a Material
Adverse Effect or materially impair the ability of the Trust or any of the Chesapeake Entities to consummate the Transactions or any other transactions provided for in
the Transaction Documents.
9
(n) No Consents. No permit, consent, approval, authorization, order, registration, filing or qualification (“Consent”) of or with any court, governmental
agency or body having jurisdiction over the Trust or its properties is required by the Trust in connection with (i) the offering, issuance or sale by the Trust of the
Trust Units as described in the Registration Statement, the Time of Sale Information and the Prospectus, (ii) the execution, delivery and performance by the Trust
of the Operative Agreements to which the Trust is a party, and (iii) the consummation by the Trust of the transactions contemplated by the Transaction
Documents to which the Trust is a party, except, in the case of clauses (i) through (iii) (A) for registration of the Units under the Securities Act and Consents
required under the Exchange Act, and applicable state securities or “Blue Sky” laws in connection with the purchase and distribution of the Units by the
Underwriters, (B) for such Consents that have been, or prior to the Initial Closing Date will be, obtained or made, and (C) for such Consents that, if not obtained,
would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect or materially impair the ability of the Trust or any of the
Chesapeake Entities to consummate the Transactions or any other transactions provided for in the Transaction Documents.
(o) No Defaults. The Trust is not (i) in violation of the Organizational Trust Agreement, the Trust Agreement or the Certificate of Trust, (ii) in violation of any
law, statute, ordinance, administrative or governmental rule or regulation applicable to it or of any order, judgment, decree or injunction of any court or governmental
agency or body having jurisdiction over it or any of its properties or assets, or (iii) in breach, default (or an event which, with notice or lapse of time or both, would
constitute such a default) or violation in the performance of any obligation, agreement, covenant or condition contained in any bond, debenture, note or any other
evidence of indebtedness or in any agreement, indenture, lease or other instrument to which it is a party or by which it or any of its properties may be bound, which
breach, default or violation in the cases of clause (ii) or (iii) would, if continued, reasonably be expected to have a Material Adverse Effect or materially impair the
ability of the Trust or any of the Chesapeake Entities to consummate the Transactions or any other transactions provided for in the Transaction Documents.
(p) Conformity of Securities to Description in the Registration Statement, the Time of Sale Information and the Prospectus. The Units, when issued and delivered
in accordance with the terms of the Trust Agreement and this Agreement against payment therefor as provided therein and herein, and the Sponsor Units and Incentive
Distribution Rights, when delivered in accordance with the terms of the Trust Agreement, will conform in all material respects to the descriptions thereof contained in
the Registration Statement, the Time of Sale Information and the Prospectus.
(q) Independent Public Accountants. PricewaterhouseCoopers LLP, which has certified or shall certify the audited financial statements of the Trust (including
the related notes thereto and supporting schedules) included in the Registration Statement, the Time of Sale Information and the Prospectus (or any amendment or
supplement thereto), is, and was during the periods covered by such financial statements, an independent registered public accounting firm with respect to the Trust as
required by the Securities Act and the Public Company Accounting Oversight Board.
(r) Financial Statements. The historical financial statements of the Trust, together with the related schedules and notes, included in the Registration Statement,
the Time of Sale Information and the Prospectus present fairly in all material respects the financial condition of
10
the Trust on the basis stated in the Registration Statement, the Time of Sale Information and the Prospectus at the respective dates or for the respective periods to which
they apply, and comply as to form with the applicable accounting requirements of the Securities Act and have been prepared in accordance with accounting principles
permitted for royalty trusts by the Commission as specified in FASB ASC Topic 932 Extractive Activities — Oil and Gas: Financial Statements of Royalty Trusts. The
summary historical and pro forma financial and operating information set forth in the Registration Statement, the Pricing Prospectus and the Prospectus under the
caption “Summary—Target Distributions and Subordination and Incentive Thresholds”, and the selected historical and pro forma financial and operating information
set forth under the caption “Target Distributions and Subordination and Incentive Thresholds” in the Registration Statement, the Pricing Prospectus and the Prospectus,
and the other financial information relating to the Trust set forth in the Registration Statement, the Time of Sale Information and the Prospectus, is accurately presented
in all material respects and prepared on a basis consistent with the audited and unaudited historical financial statements and pro forma financial statements, as
applicable, from which it has been derived. There are no other financial statements (historical or pro forma) that are required to be included in the Registration
Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto).
(s) Pro Forma Financial Statements. The pro forma financial statements of the Trust included in the Registration Statement, the Time of Sale Information and
the Prospectus include assumptions that provide a reasonable basis for presenting the significant effects directly attributable to the transactions and events described
therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma adjustments reflect the proper application of those
adjustments to the historical financial statement amounts in the pro forma financial statements included in the Registration Statement, the Time of Sale Information and
the Prospectus. The pro forma financial statements included in the Registration Statement, the Time of Sale Information and the Prospectus comply as to form in all
material respects with the applicable accounting requirements of Regulation S-X under the Securities Act and the pro forma adjustments have been properly applied to
the historical amounts in the compilation of those statements.
(t) No Changes Since Trust Formation. Since the date the Trust was formed through the date hereof, and except as may otherwise be disclosed in the
Registration Statement, the Time of Sale Information or the Prospectus, the Trust has not (i) issued or granted any Trust Securities, (ii) incurred any liability or
obligation, direct or contingent other than liabilities and obligations that were incurred in the ordinary course of business and except for this Agreement and the
Operative Agreements, (iii) entered into any transaction not in the ordinary course of business or (iv) made any distribution on its equity interests.
(u) Legal Proceedings or Contracts to be Described or Filed. There are no legal or governmental proceedings pending, or to the knowledge of the Trust and the
Company, threatened, against the Trust, or to which the Trust is a party, or to which the business or assets of the Trust is or may be subject, that are required to be
described in the Registration Statement, the Time of Sale Information or the Prospectus that are not described as required by the Securities Act. There are no
agreements, contracts, indentures, leases or other instruments to which the Trust is party that are required to be described in the Registration Statement, the Time of Sale
Information or the Prospectus or to be filed as exhibits to the Registration Statement that
11
are not described or filed as required by the Securities Act. Each contract, document or other agreement to which the Trust is party and which is described in the
Registration Statement, the Time of Sale Information or the Prospectus is in full force and effect and is valid and enforceable by and against the Trust in accordance
with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws relating
to or affecting creditors’ rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law)
and except as would not reasonably be expected to have a Material Adverse Effect.
(v) Certain Relationships and Related Transactions. Except as set forth in the Registration Statement, the Time of Sale Information and the Prospectus, there are
no transactions with “ affiliates ” (as defined in Rule 405 promulgated under the Securities Act) of the Trust or any unitholder of the Trust (whether or not an affiliate)
that are required by the Securities Act to be disclosed in the Registration Statement, the Time of Sale Information or the Prospectus. Additionally, no relationship, direct
or indirect, exists between the Trust, on the one hand, and the Trustee or unitholders of the Trust, on the other hand, that is required by the Securities Act to be disclosed
in the Registration Statement, the Time of Sale Information and the Prospectus that is not so disclosed.
(w) Books and Records. The Trust (i) makes and keeps books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of its assets and (ii) maintains systems of internal accounting controls sufficient to provide reasonable assurances that (A) transactions are executed in
accordance with management’s general or specific authorization; (B) transactions are recorded as necessary to permit preparation of its financial statements in
conformity with generally accepted accounting principles and to maintain accountability for its assets; (C) access to its assets is permitted only in accordance with
general or specific authorization of management or the Trustee, as applicable; and (D) the recorded accountability for assets is compared with existing assets at
reasonable intervals and appropriate action is taken with respect to any differences.
(x) No Previous Sale. Except as described in the Time of Sale Information, the Trust has not sold, issued or distributed any Trust Units or other securities of the
Trust during the six-month period preceding the date hereof, including any sales pursuant to Rule 144A under, or Regulation D or S of, the Securities Act.
(y) Disclosure Controls and Procedures. (i) The Trust has established and maintains disclosure controls and procedures (to the extent required by and as such
term is defined in Rule 13a-15 under the Exchange Act), (ii) such disclosure controls and procedures are designed to ensure that the information required to be disclosed
by the Trust in the reports it files or will file or submit under the Exchange Act, as applicable, is accumulated and communicated to the Trustee to allow timely
decisions regarding required disclosure to be made and (iii) such internal controls and procedures are effective in all material respects to perform the functions for
which they were established to the extent required by Rule 13a-15 under the Exchange Act.
(z) No Changes in Internal Controls. Since the date of the most recent balance sheet of the Trust reviewed or audited by PricewaterhouseCoopers LLP,
(i) neither the Company nor the Trust is aware of (A) any significant deficiencies in the design or operation of internal controls that could adversely affect the ability of
the Trust to record, process, summarize and report financial data in any material respect, or any material weaknesses in internal controls or
12
(B) any fraud, whether or not material, that involves management or other employees who have a significant role in the internal controls of the Trust, and (ii) such
internal controls and procedures are reasonably effective in all material respects to perform the functions for which they were established to the extent required by Rule
13a-15 under the Exchange Act.
(aa) Investment Company. The Trust is not, and after sale of the Units to be sold by the Trust hereunder and application of the net proceeds from such sale as
described in the Registration Statement, the Time of Sale Information and the Prospectus under the caption “Use of Proceeds,” will not be, an “investment company” or
a company “controlled by” an “investment company” within the meaning of the Investment Company Act of 1940, as amended (the “ Investment Company Act ”).
(bb) Sarbanes-Oxley Act and NYSE. At each Closing Date, the Trust will be in compliance in all material respects with all applicable provisions of the
Sarbanes-Oxley Act of 2002, the rules and regulations promulgated therewith and the rules of the New York Stock Exchange (“NYSE”) that are effective and
applicable to the Trust on such date.
(cc) Authorization and Qualification of Trustee. The Trustee is a national banking association duly authorized and empowered to act as trustee of the Trust
pursuant to the Organizational Trust Agreement and the Trust Agreement.
(dd) Litigation. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, there is (i) no action, suit or proceeding
before or by any court, arbitrator or governmental agency, body or official, domestic or foreign, now pending or, to the knowledge of the Company or the Trust,
threatened, to which the Trust is or may be a party or to which the Underlying Properties or the business or property of the Trust is or may be subject, (ii) no injunction,
restraining order or order of any nature issued by a federal or state court or foreign court of competent jurisdiction to which the Trust is or may be subject, that, in the
case of clauses (i) and (ii) above, is reasonably expected to, individually, or in the aggregate, have a Material Adverse Effect or materially impair the ability of the Trust
or any of the Chesapeake Entities to consummate the Transactions or any other transactions provided for in the Transaction Documents.
(ee) Foreign Corrupt Practices Act. Neither the Trust nor any of its affiliates (other than the trustees of the Trust or Chesapeake and its subsidiaries
acting in their respective individual capacities), nor any trustee of the Trust, nor, to the knowledge of the Trust and the Company, any agent or representative of the
Trust or its affiliates (other than the trustees of the Trust or Chesapeake and its subsidiaries acting in their respective individual capacities), has taken or will take any
action in furtherance of an offer, payment, promise to pay, or authorization or approval of the payment or giving of money, property, gifts or anything else of value,
directly or indirectly, to any “government official” (including any officer or employee of a government or government-owned or controlled entity or of a public
international organization, or any person acting in an official capacity for or on behalf of any of the foregoing, or any political party or party official or candidate for
political office) to influence official action or secure an improper advantage for the Trust; and the Trust has conducted its business in compliance with applicable
anti-corruption laws and has instituted and maintained and will continue to maintain policies and procedures designed to promote and achieve compliance with such
laws and with the representation and warranty contained herein.
13
(ff) Anti-Money Laundering. The operations of the Trust have been conducted at all times in material compliance with all applicable
financial recordkeeping and reporting requirements, including those of the Bank Secrecy Act, as amended by Title III of the Uniting and Strengthening
America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001 (USA PATRIOT Act), and the applicable anti-money
laundering statutes of jurisdictions where the Trust conducts business, the rules and regulations thereunder and any related or similar rules, regulations or
guidelines, issued, administered or enforced by any governmental agency (collectively, the “ Trust Anti-Money Laundering Laws ”), and no action, suit
or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving the Trust with respect to the Trust Anti-Money
Laundering Laws is pending or, to the knowledge of the Trust or the Company, threatened.
(gg) Office of Foreign Assets Control.
(i) Neither the Trust or any trustee of the Trust, or, to the knowledge of the Trust or the Company, any agent or representative of the Trust (other than the
trustees of the Trust or Chesapeake and its subsidiaries acting in their respective individual capacities), is an individual or entity (“ Person ”) that is, or is owned or
controlled by a Person that is:
1
the subject of any sanctions administered or enforced by the U.S. Department of Treasury’s Office of Foreign Assets Control, the United Nations Security
Council, the European Union, Her Majesty’s Treasury or other relevant sanctions authority (collectively, “ Sanction s ”), nor
2
located, organized or resident in a country or territory that is the subject of Sanctions (including, without limitation, Burma/Myanmar, Cuba, Iran, North
Korea, Sudan, Libya and Syria).
(ii) The Trust will not, directly or indirectly, use the proceeds of the offering, or lend, contribute or otherwise make available such proceeds to any subsidiary,
joint venture partner or other Person:
1
to fund or facilitate any activities or business of or with any Person or in any country or territory that, at the time of such funding or facilitation, is the
subject of Sanctions; or
2
in any other manner that will result in a violation of Sanctions by any Person (including any Person participating in the offering, whether as underwriter,
advisor, investor or otherwise).
(iii) Since the date of the Trust’s formation, the Trust has not knowingly engaged in, is not now knowingly engaged in, and will not engage in, any dealings or
transactions with any Person, or in any country or territory, that at the time of the dealing or transaction is or was the subject of Sanctions.
(hh) No Distribution of Other Offering Materials. Neither the Company nor the Trust has distributed and, prior to the latest to occur of the Initial Closing Date,
any Additional Closing
14
Date and completion of the distribution of the Units, will not distribute, any offering material in connection with the offering and sale of the Units other than the
Registration Statement, any Preliminary Prospectus, the Time of Sale Information, the Prospectus and any Issuer Free Writing Prospectus listed on Schedule II
hereto, to which the Representatives have consented in accordance with this Agreement.
(ii) Listing. The Common Units have been approved for listing on the NYSE under the symbol “CHKR.”
(jj) Market Stabilization. The Trust has not taken, and will not take, directly or indirectly, any action designed to or that would constitute or that might
reasonably be expected to cause or result in, under the Exchange Act or otherwise, stabilization or manipulation of the price of Units or facilitate the sale or resale of the
Units.
(kk) Directed Unit Program. At their respective Effective Dates or issue date and each applicable Closing Date, the Registration Statement, the Pricing
Prospectus, the Time of Sale Information and the Prospectus complied or will comply, and any amendments or supplements thereto will comply, with any applicable
laws or regulations of foreign jurisdictions in which the Pricing Prospectus, the Time of Sale Information and the Prospectus, as amended or supplemented, if
applicable, are distributed in connection with the Directed Unit Program (as defined in Section 2 below).
(ll) Directed Unit Authorization. No consent, approval, authorization or order of, or qualification with, any governmental body or agency, other than those
obtained, is required in connection with the offering of the Directed Units (as defined in Section 2 below) in any jurisdiction where the Directed Units are being offered.
(mm) Directed Unit Qualification. The Trust has not offered, or caused Morgan Stanley to offer, Units to any person pursuant to the Directed Unit Program (as
defined in Section 2 below) with the specific intent to unlawfully influence (a) a customer or supplier of the Company to alter the customer’s or supplier’s level or type
of business with the Company, or (b) a trade journalist or publication to write or publish favorable information about the Company, the Trust or their products.
(nn) No Consent Needed for Trustee Action. No Consent, other than those obtained prior to the date hereof, is required under any law, rule or regulation of the
State of Delaware, the State of Oklahoma, the State of Texas, or the United States of America, in order to permit the Trustee to act as Trustee of the Trust.
(oo) Accuracy of Statements in Prospectus. The statements set forth in the Prospectus under the caption “Description of the Trust Units,” insofar as they purport
to constitute a summary of the terms of the Trust Units, and the statements under the captions “The Trust,” “Description of the Royalty Interests,” “Description of the
Trust Agreement” and “Description of the Trust Units,” fairly and accurately describe the provisions of the laws and documents referred to therein in all material
respects.
1.2 Of The Company. The Company hereby represents and warrants to each Underwriter on the date hereof, and shall be deemed to represent and warrant to, and
agree with, each Underwriter on each Closing Date, that:
(a) Company Not an “Ineligible Issuer.” The Company was not at the time of initial filing of the Registration Statement, is not on the date hereof and will
not be on the applicable Closing Date an “ineligible issuer” (as defined in Rule 405 under the Securities Act).
15
(b) Form S-3 Eligibility. The Company and the transactions contemplated by the Operative Agreements to which the Company is a party
meet the requirements for and comply with the conditions for the use of Form S-3 under the Securities Act.
(c) Free Writing Prospectus. Any Issuer Free Writing Prospectus that the Company is required to file pursuant to Rule 433(d) under the Securities Act
has been, or will be, filed with the Commission in accordance with the requirements of the Securities Act. Each Issuer Free Writing Prospectus that the Company has
filed, or is required to file, pursuant to Rule 433(d) under the Securities Act or that was prepared by or on behalf of or used or referred to by the Company complies or
will comply in all material respects with the requirements of the Securities Act and the applicable rules and regulations of the Commission thereunder. Except for the
Free Writing Prospectuses, if any, identified in Schedule II hereto, and electronic road shows, if any, each furnished to you before first use, the Company has not
prepared, used or referred to, or will not, without your prior consent, prepare, use or refer to, any Free Writing Prospectus in connection with the offering of the Units.
(d) Forward-Looking and Statistical Information. The statistical and market related data and forward looking statements (including the assumptions
described therein) included in the Registration Statement and Time of Sale Information and to be made in the Prospectus (in the case of forward-looking statements,
within the coverage of Rule 175(b) under the Securities Act), including (but not limited to) any statements with respect to projected results of operations, estimated cash
available for distribution and future cash distributions of the Trust or the anticipated ratio of taxable income to distributions, and any statements made in support thereof
or related thereto, is based on or derived from sources that the Company believes to be reliable and accurate in all material respects and was made or will be made with
a reasonable basis and in good faith on the bases of data derived from such sources.
(e) Formation, Due Qualification and Authority. Each of the Chesapeake Entities has been duly formed and is validly existing as a corporation or limited
liability company, as applicable, in good standing under the laws of its jurisdiction of incorporation or formation, as the case may be, with full power and authority to
own, lease and operate its properties and to conduct its business as presently conducted and as described in the Registration Statement, the Time of Sale Information and
the Prospectus (and any amendment or supplement thereto) and is duly registered and qualified to conduct its business and is in good standing in each jurisdiction or
place where the nature of its properties or the conduct of its business requires such registration or qualification, except where the failure to so register or qualify has not
and would not reasonably be expected to (i) have a Material Adverse Effect, (ii) materially impair the ability of any of the Chesapeake Entities to consummate the
Transactions or any other transactions provided for in the Transaction Documents or (iii) subject the unitholders of the Trust to any material liability or disability.
(f) Ownership of Chesapeake Exploration and Assignee. The Company owns, directly or indirectly, 100% of the outstanding equity interests of
Chesapeake Exploration and Assignee. All of such equity interests have been duly authorized and validly issued and are fully paid and non-assessable.
16
(g) Incorporated Documents. The Incorporated Documents, at the time they were filed with the Commission, complied in all material
respects with the Exchange Act and the applicable rules and regulations of the Commission thereunder. Each of the Incorporated Documents, as of the
Time of Sale and at each Closing Date, did not contain and, as amended, if applicable, will not contain any untrue statement of a material fact or omit to
state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.
(h) Outstanding Trust Units Held by Company. At the Initial Closing Date, after giving effect to the Transactions and assuming no exercise of the
Underwriters’ option to purchase Additional Units, the Company will own [11,437,500] Common Units and [11,437,500] Subordinated Units free and clear of all Liens.
(i) No Preemptive Rights, Registration Rights or Options. Except as described in the Registration Statement, the Time of Sale Information and the
Prospectus, there are no options, warrants, preemptive rights or other rights issued or granted by the Company to subscribe for or to purchase, nor any restriction (other
than applicable securities laws) upon the voting or transfer of, any Trust Securities (as defined herein).
(j) Authorization of Underwriting Agreement. This Agreement has been duly authorized and validly executed and delivered by the Company.
(k) Authority and Authorization. The Company has all requisite corporate power and authority to execute and deliver this Agreement and to perform its
obligations hereunder. At each Closing Date, all corporate action required to be taken by the Company or any of its stockholders, directors or officers for the execution
and delivery of the Operative Agreements to which the Company is a party and the consummation by the Company of the Transactions and any other transactions
contemplated by this Agreement and the Operative Agreements to which the Company is a party shall have been validly taken.
(l) Enforceability of Operative Agreements. At or before the Initial Closing Date, each of the Operative Agreements will have been duly authorized,
executed and delivered by the Chesapeake Entities party thereto, and will be a valid and legally binding agreement of the applicable Chesapeake Entity, enforceable
against such Chesapeake Entity in accordance with each of its terms, except as such enforceability may be limited by (i) bankruptcy, insolvency, fraudulent transfer,
reorganization, moratorium and similar laws relating to or affecting creditors’ rights generally and by general principles of equity (regardless of whether such
enforceability is considered in a proceeding in equity or at law), and (ii) public policy, any applicable law relating to fiduciary duties and indemnification and an
implied covenant of good faith and fair dealing.
(m) Authorization and Enforceability of the Conveyance Documents. The Conveyance Documents among the Company, Chesapeake Exploration,
Assignee and the Trust, when duly executed by the proper officers of the Company, Chesapeake Exploration and
17
Assignee (assuming due execution and delivery by the Trustee) and delivered by the Company, Chesapeake Exploration and Assignee to the Trust, will constitute a
fully conveyed and vested interest in real property under the laws of the State of Oklahoma, and are adequate and sufficient to transfer title to the Royalty Interests to
the Trust; the recording of the Conveyance Documents in the Office of the County Clerk in Washita County is sufficient to impart notice of the contents thereof, and all
subsequent purchasers or creditors of the Company (to the extent any such transaction concerns the Underlying Properties) will be deemed to purchase with notice of
and subject to such Royalty Interests; the Conveyance Documents and the Royalty Interests conform in all material respects to the descriptions thereof in the
Registration Statement, the Time of Sale Information and the Prospectus; and the Royalty Interests are described in the Conveyance Documents in a manner sufficient
to identify the interests conveyed under the laws of the State of Oklahoma. To the knowledge of the Company, the Company’s net revenue interest with respect to each
Subject Well or Subject Lease (as such terms are defined in the Conveyances) is no less than the net revenue interest set forth on the exhibits to the Conveyances.
(n) No Conflicts. None of (i) the offering, issuance or sale of the Trust Units as described in the Registration Statement, the Time of Sale Information and
the Prospectus, (ii) the execution, delivery and performance of the Operative Agreements by the Trust and the Chesapeake Entities party hereto and thereto, and (iii) the
consummation of the Transactions, (A) conflicts with or will conflict with or constitutes or will constitute a violation or breach of, or a default under, any of the
Chesapeake Entities’ Organizational Documents, (B) conflicts with or will conflict with or constitutes or will constitute a breach or violation of, or a default (or an event
which, with notice or lapse of time or both, would constitute such a default) under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or
instrument to which any of the Chesapeake Entities is a party or by which any of their respective properties may be bound, (C) violates or will violate any statute, law,
regulation, ruling or any order, judgment, decree or injunction of any court or governmental agency or body directed to any Chesapeake Entity or its properties in a
proceeding to which it or its properties is a party or is bound or (D) results or will result in the creation or imposition of any Liens, upon any property or assets of any of
the Chesapeake Entities, except with respect to clauses (B) - (D) for such conflicts, violations, breaches, defaults or Liens that would (i) reasonably be expected to have,
individually or in the aggregate, a Material Adverse Effect or (ii) materially impair the ability of the Trust or any of the Chesapeake Entities to consummate the
Transactions or any other transactions provided for in the Transaction Documents.
(o) No Consents. No Consent of or with any court, governmental agency or body having jurisdiction over any of the Chesapeake Entities or their
respective properties is required by any of the Chesapeake Entities in connection with (i) the offering, issuance and sale of the Trust Units as described in the
Registration Statement, the Time of Sale Information and the Prospectus, (ii) the execution, delivery and performance of the Operative Agreements by the Trust or any
of the Chesapeake Entities party hereto or thereto, and (iii) the consummation by the Trust of the transactions contemplated by the Transaction Documents to which the
Trust is a party, except, in the case of clauses (i) through (iii) (A) for registration of the Units under the Securities Act and Consents required under the Exchange Act,
and applicable state securities or “Blue Sky” laws in connection with the purchase and distribution of the Units by the Underwriters, (B) for such Consents that have
been, or prior to the Initial Closing Date will be, obtained or made, (C) for such Consents that, if not obtained, would not reasonably be expected
18
to have, individually or in the aggregate, a Material Adverse Effect or materially impair the ability of the Trust or any of the Chesapeake Entities to consummate the
Transactions or any other transactions provided for in the Transaction Documents and (D) except as described in the Registration Statement, the Time of Sale
Information and the Prospectus.
(p) No Defaults. None of the Chesapeake Entities is (i) in violation of its Organizational Documents, (ii) in violation of any law, statute, ordinance,
administrative or governmental rule or regulation applicable to it or of any order, judgment, decree or injunction of any court or governmental agency or body having
jurisdiction over it or any of its properties or assets or (iii) in breach, default (or an event which, with notice or lapse of time or both, would constitute such a default) or
violation in the performance of any obligation, agreement, covenant or condition contained in any bond, debenture, note or any other evidence of indebtedness or in any
agreement, indenture, lease or other agreement or instrument to which it is a party or by which it or any of its properties or assets may be bound, which breach, default
or violation in the case of clauses (ii) or (iii) would, if continued, reasonably be expected to have a Material Adverse Effect or materially impair the ability of the Trust
or any of the Chesapeake Entities to consummate the Transactions or any other transactions provided for in the Transaction Documents.
(q) Independent Public Accountants. PricewaterhouseCoopers LLP, who has certified or shall certify the audited financial statements of the Underlying
Properties and the Company included in the Registration Statement, the Time of Sale Information and the Prospectus (including the related notes thereto and supporting
schedules), is, and was during the periods covered by such financial statements, an independent registered public accounting firm with respect to the Company as
required by the Securities Act and the Public Company Accounting Oversight Board.
(r) Financial Statements. The financial statements of the Company and the Underlying Properties, together with the related schedules and notes, included
in the Registration Statement, the Time of Sale Information and the Prospectus, present fairly in all material respects the financial condition of the Company and the
Underlying Properties on the basis stated in the Registration Statement, the Time of Sale Information and the Prospectus at the respective dates or for the respective
periods to which they apply. Such statements and related schedules and notes have been prepared in accordance with generally accepted accounting principles
consistently applied throughout the periods involved; and the other financial information relating to the Company and the Underlying Properties set forth in the
Registration Statement, the Time of Sale Information and the Prospectus is accurately presented in all material respects and prepared on a basis consistent with such
financial statements and the books and records of the Company. No other financial statements or schedules are required to be included in the Registration Statement, the
Time of Sale Information and the Prospectus (and any amendment or supplement thereto). The other financial information of the Company and the Underlying
Properties contained in the Registration Statement, the Time of Sale Information and the Prospectus has been derived from the accounting records of the Company and
its subsidiaries, and fairly presents in all material respects the information purported to be shown thereby.
(s) No Material Adverse Change. There has not occurred any material adverse change, or any development involving a prospective material adverse
change, in the
19
condition, financial or otherwise, or in the earnings, business or operations of the Company and its subsidiaries, taken as a whole, or the Underlying Properties, from
that set forth in the Time of Sale Information.
(t) Legal Proceedings or Contracts to be Described or Filed. There are no legal or governmental proceedings pending, or to the knowledge of the
Company, threatened, against the Company or its subsidiaries, or to which the Company or its subsidiaries is a party, or to which the business or assets of the Company
or its subsidiaries is or may be subject, that are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus that are not
described as required by the Securities Act. There are no agreements, contracts, indentures, leases or other instruments to which the Company or its subsidiaries is party
that are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus or to be filed as exhibits to the Registration Statement
that are not described or filed as required by the Securities Act.
(u) Title to Properties. Chesapeake Exploration, as of the Initial Closing Date, will have good and defensible title to the Subject Interests (as defined in
the Conveyances), free and clear of all liens, encumbrances and defects except (i) those described in the Registration Statement, Prospectus or the Time of Sale
Information; (ii) the terms of the oil and gas leases, including the royalties and other burdens and obligations, expressed and implied, under oil and gas leases;
(iii) overriding royalties, production payments and similar interests and other burdens created by Chesapeake Exploration or its predecessors in title; (iv) contractual
obligations arising under operating agreements, farm-out agreements, production sales contracts, gathering agreements, transportation agreements, treating agreements,
processing agreements, leases, assignments and other similar agreements that may affect the Subject Interests; (v) liens that arise in the normal course of operations,
such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements, in each case to secure
payments of amounts that are not yet delinquent or, if delinquent are being contested in good faith in the normal course of business; (vi) pooling and unitization
agreements, declarations and orders; (vii) easements, rights-of-way servitudes, permits, surface leases, surface use restrictions and other surface uses and impediments
on, over or in respect of the Subject Interests that are not such as to interfere materially with the operation, value or use of the Subject Interests; (viii) conventional
rights of reassignment that obligate Chesapeake Exploration to reassign all or part of any Subject Interest to a third party if Chesapeake Exploration intends to release or
abandon each interest before the expiration of the primary term or other termination of such interest; (ix) rights reserved to or vested in appropriate governmental
agencies or authorities to control or regulate any Subject Interest in any manner, and all applicable Legal Requirements (as defined in the Conveyances); (x) all rights to
consent by, required notices to, filings with or other actions by governmental agencies or authorities in connection with the sale, disposition, transfer or conveyance of
federal, state, tribal or other governmental oil and gas leases or interests therein or related thereto where the same are customarily obtained subsequent to the
assignment, disposition or transfer of such oil and gas leases or interests therein; (xi) matters that are customarily acceptable title defects (such as, but not limited to,
defects that have been cured by possession under applicable statutes of limitation, defects in the early chain of title such as failure to recite marital status in documents,
omission of heirship or succession proceedings, lack of survey, and failure to record releases of liens, production payments or mortgages that have expired by their own
terms or the enforcement of which are barred by applicable statutes of
20
limitation) and that do not (A) result in another person’s superior claim of title to the relevant Subject Interest or (B) in the aggregate, interfere materially with the
operation, value or use of the Subject Interests; and (xii) all other liens, charges, encumbrances, contracts, agreements, instruments, obligations, conditions, reservations,
burdens, defects and irregularities affecting the Subject Interests that (A) do not secure an obligation in respect of borrowed money and (B) are not such as to (in the
aggregate) interfere materially with the operation, value or use of the Subject Interests; provided that such aforementioned encumbrances are of the type and nature
customary in the oil and gas industry and do not, alone or in the aggregate materially and adversely affect the operation, value or use of the Subject Interests. All
contracts, agreements or underlying leases, which comprise a portion of the Subject Interests and which individually or in the aggregate are material to the Subject
Interests, are in full force and effect, Chesapeake Exploration has paid all rents and other charges to the extent due and payable thereunder, is not, to the knowledge of
the Company, in default under any of such underlying contracts, agreements or leases, has received no notice of default from any other party thereto and knows of no
material default by any other party thereto. The working interests in oil, gas and mineral leases or mineral interests that constitute a portion of the Subject Interests held
by Chesapeake Exploration reflect in all material respects the right of Chesapeake Exploration to explore or receive production from such Subject Interests and the care
taken by Chesapeake Exploration with respect to acquiring or otherwise procuring such leases or mineral interests was generally consistent with standard industry
practices for acquiring or procuring leases and interests therein to explore such for hydrocarbons. Upon recordation and filing of the Conveyance Documents, the Trust
will have good and defensible title to the Royalty Interests, free and clear of all Liens, except Permitted Encumbrances (as defined in the Conveyances), in all cases by,
through or under Chesapeake Exploration and any predecessor Affiliate (as defined in the Conveyances) of Chesapeake Exploration, but not otherwise, such that (i) in
the case of each PDP Conveyance, the Trust shall be entitled to a share of the Subject Minerals (as defined in the PDP Conveyances) produced from each Well (as
defined in the PDP Conveyances), or the proceeds thereof, equal to forty-five percent (45%) of the Assignor’s Net Revenue Interest (as defined in the PDP
Conveyances) set forth on Exhibit C to such PDP Conveyance in each such Well , and (ii) in the case of each PUD Conveyance, the Trust shall be entitled to a share of
the Subject Minerals (as defined in the PUD Conveyances) produced from each Development Well (as defined in the PUD Conveyances), or the proceeds thereof, equal
to twenty-five percent (25%) of the Assignor’s Net Revenue Interest (as defined in the PUD Conveyances) in each such Development Well used to calculate the NRI
Factor (as defined in the Development Agreement) for such Development Well pursuant to the Development Agreement. As of the Initial Closing Date, except for
Permitted Encumbrances (as defined in the Conveyances), any and all Liens on the Subject Interests will be subordinated to the Royalty Interests and all future liens or
encumbrances on the Subject Interests shall be subordinate and inferior to the Royalty Interests.
(v) Rights-of-Way. Chesapeake Exploration or its Affiliate (as defined in the Conveyances) has such easements, rights-of-way or other similar agreement
from each person (collectively, “ rights-of-way ”) as are necessary to conduct its operations with respect to the Underlying Properties in the manner described in the
Registration Statement, the Time of Sale Information and the Prospectus, except for such rights-of-way that, if not obtained, would not reasonably be expected to have,
individually or in the aggregate, a Material Adverse Effect; Chesapeake Exploration or its Affiliate has fulfilled and performed all its material obligations with respect
to such rights-of-way, and no event has occurred that allows, or after notice or lapse
21
of time would allow, revocation or termination thereof or would result in any impairment of the rights of Chesapeake Exploration or such Affiliate with respect to such
rights-of-way, except for such revocations, terminations and impairments that would not reasonably be expected to have, individually or in the aggregate, a Material
Adverse Effect; and none of such rights-of-way contains any restriction that would reasonably be expected to have, individually or in the aggregate, a Material Adverse
Effect.
(w) Governmental Permits. Each of the Chesapeake Entities has, or at each Closing Date, will have, such permits, consents, licenses, franchises,
certificates and authorizations of governmental or regulatory authorities (“ governmental permits ”) as are necessary to own or lease the Underlying Properties and to
conduct its business with respect to the Underlying Properties in the manner described in the Registration Statement, the Time of Sale Information and the Prospectus,
subject to such qualifications set forth in the Registration Statement, the Time of Sale Information and the Prospectus and except for such governmental permits that, if
not obtained, would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect, and the Chesapeake Entities have not received any
notice of proceedings relating to the revocation or modification of any such certificate, authority or permit that, if determined adversely to the Company or any of its
subsidiaries, would reasonably be expected to individually or in the aggregate have a Material Adverse Effect, nor, to the knowledge of the Company, have such
proceedings been threatened.
(x) Reserve Reports.
(i) The written engineering reports prepared by (i) Ryder Scott Company, L.P., (ii) Netherland Sewell & Associates, Inc., (iii) Lee Keeling and Associates,
Inc., and (iv) Data and Consulting Services, Division of Schlumberger Technology Corporation (together, the “ Company Independent Petroleum Engineers ”), as
of December 31, 2010 setting forth the engineering values attributed to the oil and gas properties of the Company and its subsidiaries accurately reflect in all material
respects the ownership interests of the Company and its subsidiaries in the properties included therein as of December 31, 2010, except as otherwise disclosed in the
Registration Statement, the Prospectus and the Time of Sale Information. The Company Independent Petroleum Engineers are independent with respect to the
Company.
(ii) The written engineering reports prepared by Ryder Scott Company, L.P. (the “Independent Petroleum Engineer”), as of June 30, 2011, setting forth the
engineering values attributed to the Underlying Properties and the Royalty Interests accurately reflect in all material respects the ownership interests of the Company
in the properties included therein as of June 30, 2011, except as otherwise disclosed in the Registration Statement, the Prospectus and the Time of Sale Information.
The information furnished by the Company to the Independent Petroleum Engineer for purposes of preparing its reports, including, without limitation, production,
costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true, correct and
complete in all material respects on the date supplied and was prepared in accordance with customary industry practices. The Independent Petroleum Engineer is
independent with respect to the Company and the Trust.
22
(y) Disclosure Controls and Procedures. (i) The Company has established and maintains disclosure controls and procedures (to the extent
required by and as such term is defined in Rule 13a-15 under the Exchange Act), (ii) such disclosure controls and procedures are designed to ensure that
the information required to be disclosed by the Company in the reports it files or will file or submit under the Exchange Act, as applicable, is accumulated
and communicated to the management of the Company, including its respective principal executive officers and principal financial officers, as appropriate,
to allow timely decisions regarding required disclosure to be made and (iii) such disclosure controls and procedures are reasonably effective in all material
respects to perform the functions for which they were established to the extent required by Rule 13a-15 of the Exchange Act.
(z) No Changes in Internal Controls. Since the date of the most recent balance sheet of the Company reviewed or audited by PricewaterhouseCoopers
LLP, (i) the Company is not aware of (A) any significant deficiencies in the design or operation of internal controls that could adversely affect the ability of the
Company to record, process, summarize and report financial data in any material respect, or any material weaknesses in internal controls or (B) any fraud, whether or
not material, that involves management or other employees who have a significant role in the internal controls of the Company, (ii) such internal controls are reasonably
effective in all material respects to perform the functions for which they were established to the extent required by Rule 13a-15 of the Exchange Act, and (iii) there have
been no significant changes in internal controls or in other factors that has or could significantly and adversely affect internal controls.
(aa) ERISA. Other than with respect to items that would not reasonably be expected to have a Material Adverse Effect, neither the Company nor any of
its subsidiaries has any liability for any prohibited transaction or accumulated funding deficiency (within the meaning of Section 412 of the Internal Revenue Code) or
any complete or partial withdrawal liability (within the meaning of Sections 4203 and 4205 of the Employee Retirement Income Security Act of 1974, as amended (“
ERISA ”), respectively), with respect to any pension, profit sharing or other plan which is subject to ERISA, to which the Company or any of its subsidiaries makes or
ever has made a contribution and in which any employee of the Company or any subsidiary is or has ever been a participant. With respect to such plans, the Company
and each of its subsidiaries is in compliance in all material respects with all applicable provisions of ERISA.
(bb) Investment Company. The Company is not, and after sale of the Trust Units to be sold by the Trust hereunder and application of the net proceeds
from such sale by the Trust and a wholly-owned subsidiary of the Company as described in the Registration Statement, the Time of Sale Information and the Prospectus
under the caption “Use of Proceeds,” will not be, an “investment company” or a company “controlled by” an “investment company” within the meaning of the
Investment Company Act.
(cc) Intellectual Property. Each of the Chesapeake Entities has, with respect to the assets to be owned or leased by such Chesapeake Entity at each
Closing Date, owns, possesses or can acquire on reasonable terms adequate rights to use all material patents, patent applications, trademarks, service marks, trade
names, trademark registrations, service mark registrations, copyrights, licenses, know-how, software, systems and technology necessary for
23
the conduct of its respective businesses in the manner and subject to such qualifications described in the Registration Statement, the Pricing Disclosure Package and the
Prospectus and has not received any notice of any claim of conflict with, any such rights of others, except for such conflicts that would not reasonably be expected to
have, individually or in the aggregate, a Material Adverse Effect.
(dd) Environmental Compliance. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, neither the
Company nor any of its subsidiaries is in violation of any statute, rule, regulation, decision or order of any governmental agency or body or any court, domestic or
foreign, relating to the use, disposal or release of hazardous or toxic substances or relating to the protection or restoration of the environment or human exposure to
hazardous or toxic substances (collectively, “ environmental laws ”), owns or operates any real property contaminated with any substance that is subject to any
environmental laws, is liable for any off-site disposal or contamination pursuant to any environmental laws, or is subject to any claim relating to any environmental
laws which violation, contamination, liability or claim would reasonably be expected to individually or in the aggregate have a Material Adverse Effect; and the
Company is not aware of any pending investigation, action, proceeding or suit which might lead to such a claim, including, but not limited to, with respect to any of the
Subject Interests (as defined in the Conveyances).
(ee) No Labor Dispute. No labor dispute with the employees of any of the Chesapeake Entities, to the knowledge of the Company, is imminent or
threatened that would reasonably be expected to have a Material Adverse Effect.
(ff) Insurance. With respect to the Underlying Properties, each of the Chesapeake Entities maintains or is entitled to the benefit of insurance covering its
properties, operations, personnel and business against such losses and risks, in such amounts and from such insurers as is commercially reasonable for the conduct of
their respective businesses and the value of their respective properties.
(gg) Litigation. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, there is (i) no action, suit or
proceeding before or by any court, arbitrator or governmental agency, body or official, domestic or foreign, now pending or, to the knowledge of the Company,
threatened, to which any of the Chesapeake Entities is or may be a party or to which the business or property of any of the Chesapeake Entities is or may be subject,
(ii) no injunction, restraining order or order of any nature issued by a federal or state court or foreign court of competent jurisdiction to which any of the Chesapeake
Entities is or may be subject, that, in the case of clauses (i) and (ii) above, is reasonably expected to (A) individually, or in the aggregate, have a Material Adverse
Effect, (B) prevent or result in the suspension of the offer, issuance or sale of the Units, or (C) call into question the validity of any of the Operative Agreements or the
consummation of the Transactions.
(hh) No Foreign Operations. During the past five years, neither the Company nor any of its subsidiaries have conducted operations, conducted business
or produced revenue from sources outside the United States.
(ii) Market Stabilization. The Company has not taken, directly or indirectly,
24
any action designed to or that would constitute or that might reasonably be expected to cause or result in, under the Exchange Act or otherwise, stabilization or
manipulation of the price of any security of the Trust or facilitate the sale or resale of the Trust Units.
(jj) FINRA Affiliations. To the knowledge of the Company, there are no affiliations or associations between any member of FINRA (as defined herein)
and any of the Company’s officers or directors, except as described in the Registration Statement, the Time of Sale Information and the Prospectus.
(kk) Directed Unit Qualification. The Company has not offered, or caused Morgan Stanley to offer, Units to any person pursuant to the Directed Unit
Program with the specific intent to unlawfully influence (a) a customer or supplier of the Company to alter the customer’s or supplier’s level or type of business with
the Company, or (b) a trade journalist or publication to write or publish favorable information about the Company, the Trust or their products.
(ll) Private Placement. The sale and issuance of the Sponsor Units and Incentive Distribution Rights to the Company are exempt from the registration
requirements of the Securities Act and securities laws of any state having jurisdiction with respect thereto, and none of the Company or the Trust has taken or will take
any action that would cause the loss of such exemption.
Any certificate signed by any officer or trustee of the Company or the Trust and delivered to the Representatives or to counsel for the Underwriters pursuant to this
Agreement shall be deemed a representation and warranty by the Company or the Trust, as applicable, to each Underwriter as to the matters covered thereby.
2. Agreements to Sell and Purchase. The Trust hereby agrees to sell to the several Underwriters, and each Underwriter, upon the basis of the representations and
warranties herein contained, but subject to the conditions hereinafter stated, agrees, severally and not jointly, to purchase from the Trust the respective numbers of Firm
Units set forth in Schedule I hereto opposite its name at $[
] per Unit (the “ Purchase Price ”).
On the basis of the representations and warranties contained in this Agreement, and subject to its terms and conditions, the Trust agrees to sell to the
Underwriters the Additional Units, and the Underwriters shall have the right to purchase, severally and not jointly, up to [3,431,250] Additional Units. The price per
Unit of any Additional Units purchased by the Underwriters shall be the Purchase Price, less an amount per Unit equal to any dividends or distributions declared by the
Trust and payable on the Firm Units but not payable on the Additional Units. The Representatives may exercise this right on behalf of the Underwriters in whole or
from time to time in part by giving written notice not later than 30 days after the date of the Prospectus. Any exercise notice shall specify the number of Additional
Units to be purchased by the Underwriters and the date on which such Units are to be purchased. Each purchase date must be at least one business day after the written
notice is given and may not be earlier than the closing date for the Firm Units nor later than ten business days after the date of such notice. Additional Units may be
purchased as provided in Section 4 hereof solely for the purpose of covering over-allotments made in connection with the offering of the Firm Units. On
25
each day, if any, that Additional Units are to be purchased (an “Additional Closing Date”), each Underwriter agrees, severally and not jointly, to purchase the number
of Additional Units (subject to such adjustments to eliminate fractional units as the Representatives may determine) that bears the same proportion to the total number
of Additional Units to be purchased on such Additional Closing Date as the number of Firm Units set forth in Schedule I hereto opposite the name of such
Underwriter bears to the total number of Firm Units.
It is further understood that up to five percent of the Firm Units (the “Directed Units”) will initially be reserved by the several Underwriters for offer and
sale upon the terms and conditions to be set forth in the most recent Preliminary Prospectus and in accordance with the rules and regulations of the Financial Industry
Regulatory Authority, Inc. (“ FINRA ”) to the officers and directors of the Company and certain other persons associated with the Company (each such person a “
Directed Unit Participant ”) who have heretofore delivered to Morgan Stanley offers to purchase Firm Units in form satisfactory to Morgan Stanley (such program, the
“ Directed Unit Program ”) and that any allocation of such Firm Units among such persons will be made in accordance with timely directions received by Morgan
Stanley from the Company; provided that under no circumstances will Morgan Stanley or any Underwriter be liable to the Trust or the Company or to any such person
for any action taken or omitted in good faith in connection with such Directed Unit Program. It is further understood that any Directed Units not affirmatively
reconfirmed for purchase by any participant in the Directed Unit Program by 9:00 a.m., New York City time, on the first business day following the date hereof or
otherwise not purchased by such persons will be offered by the Underwriters to the public upon the terms and conditions set forth in the Prospectus.
3. Terms of Public Offering. The Trust and the Company are advised by the Representatives that the Underwriters propose to make a public offering of their
respective portions of the Units as soon after the Registration Statement and this Agreement have become effective as in the Representatives’ judgment is advisable.
The Trust and the Company are further advised by the Representatives that the Units are to be offered to the public initially at $[
] per Unit (the “ Public
Offering Price ”).
4. Delivery of the Units and Payment Therefor. Delivery to the Underwriters of the Firm Units and payment therefor shall be made at the offices of Bracewell &
Giuliani LLP, 711 Louisiana, Houston, Texas 77002 at 9:00 a.m., Houston, Texas time, on [ ], 2011 or such other place, time and date not later than 12:30 p.m.,
Houston, Texas time, on [ ], 2011 as the Representatives shall designate by notice to the Trust and the Company (the time and date of such closing are called the “
Initial Closing Date ” and each of the Initial Closing Date and the Additional Closing Date being referred to as a “ Closing Date ”). The place of closing for the Firm
Units and the Initial Closing Date may be varied by agreement among the Representatives, the Trust and the Company. The Trust and the Company hereby
acknowledge that circumstances under which the Representatives may provide notice to postpone the Initial Closing Date as originally scheduled include any
determination by the Trust, the Company or the Representatives to recirculate to the public copies of an amended or supplemental Prospectus or a delay as contemplated
by the provisions of Section 10 hereof.
Delivery to the Underwriters and payment for any Additional Units to be purchased by the Underwriters shall be made at the offices of Bracewell & Giuliani
LLP, 711 Louisiana,
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Houston, Texas 77002 at 9:00 a.m., Houston, Texas time, on each Additional Closing Date as shall be specified in a written notice or notices, from the Representatives
on behalf of the Underwriters to the Company and the Trust (as described in Section 2 above). The place of closing for the Additional Units and the Additional Closing
Date may be varied by agreement among the Representatives, the Trust and the Company.
Delivery of the Firm Units and of any Additional Units to be purchased hereunder shall be made through the facilities of The Depository Trust Company against
payment of the purchase price therefor by wire transfer of immediately available funds to an account or accounts specified in writing, not later than the close of business
on the business day next preceding the Initial Closing Date or the Additional Closing Date, as the case may be, by the Trust. Payment for the Firm Units sold by the
Trust hereunder shall be delivered by the Representatives to the Trust. Payment for the Additional Units sold by the Trust hereunder, if any, shall be delivered by the
Representatives to the Trust.
It is understood that the Representatives have been authorized, for their own accounts and the accounts of the Underwriters, to accept delivery of and receipt for,
and make payment of the Purchase Price for the Firm Units and the Additional Units, if any, that the Underwriters have agreed to purchase. Morgan Stanley & Co. LLC
and Raymond James & Associates, Inc., each individually and not as a Representative of the Underwriters, may, but shall not be obligated to, make payment for any
Units to be purchased by any Underwriter whose funds shall not have been received by the Representatives by the Initial Closing Date or the Additional Closing Date,
as the case may be, for the account of such Underwriter, but any such payment shall not relieve such Underwriter from any of its obligations under this Agreement.
5. Covenants and Agreements. Each of the Company and the Trust, each as to itself, covenants and agrees with the several Underwriters as follows:
(a) To furnish to you, without charge, three signed copies of the Registration Statement (including exhibits thereto) and for delivery to each other Underwriter a
conformed copy of the Registration Statement (without exhibits thereto) and to furnish to you, in New York City, without charge, no later than the business day prior to
the Initial Closing Date and during the periods mentioned in Sections 5(g) and 5(h) below, as many copies of the Time of Sale Information, the Prospectus and any
supplements and amendments thereto or to the Registration Statement as you may reasonably request.
(b) Before amending or supplementing the Registration Statement, and Preliminary Prospectus, the Time of Sale Information or the Prospectus, to furnish to you
a copy of each such proposed amendment or supplement and not to file any such proposed amendment or supplement to which you reasonably object, and to file with
the Commission within the applicable period specified in Rule 424(b) under the Securities Act any prospectus required to be filed pursuant to such Rule.
(c) Not to make any offer relating to the Units that would constitute an Issuer Free Writing Prospectus without your prior consent, which consent shall not be
unreasonably withheld, conditioned or delayed.
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(d) Not to take any action that would result in an Underwriter, the Company or the Trust being required to file with the Commission pursuant to Rule
433(d) under the Securities Act a Free Writing Prospectus prepared by or on behalf of the Underwriter that the Underwriter otherwise would not have been
required to file thereunder.
(e) To furnish such information as may be required and otherwise to cooperate in qualifying the Units for offering and sale under the securities or “Blue Sky”
laws of such states or other jurisdictions as you may designate and to maintain such qualifications in effect so long as you may request for the distribution of the Units,
provided that in no event shall the Company or the Trust be obligated to qualify to do business in any jurisdiction where it is not now so qualified or to take any action
that would subject it to general service of process in suits, other than those arising out of the offering or sale of the Units, as contemplated by this Agreement and the
Prospectus, in any jurisdiction where it is now subject. In the event that the qualification of the Units in any jurisdiction is suspended, or any proceeding for such
purpose is initiated or threatened, the Company and the Trust shall so advise you promptly in writing.
(f) To advise you promptly, confirming such advice in writing, of any request by the Commission for amendments or supplements to the Registration Statement,
any Preliminary Prospectus, the Prospectus or any Issuer Free Writing Prospectus or for additional information with respect thereto, or of notice of institution of
proceedings for, or the entry of a stop order, suspending the effectiveness of the Registration Statement and, if the Commission should enter a stop order suspending the
effectiveness of the Registration Statement, to use its reasonable best efforts to obtain the lifting or removal of such order as soon as practicable; to advise you promptly
of any proposal to amend or supplement the Registration Statement, any Preliminary Prospectus or the Prospectus (or to deliver correspondence to the Commission) in
response to such events, and to provide you and Underwriters’ counsel copies of any such documents for review and comment a reasonable amount of time prior to any
proposed filing and to file no such amendment or supplement or correspondence to which you shall reasonably object in writing.
(g) If the Time of Sale Information is being used to solicit offers to buy the Units at a time when the Prospectus is not yet available to prospective purchasers and
any event shall occur or condition exist as a result of which it is necessary to amend or supplement the Time of Sale Information in order to make the statements therein,
in the light of the circumstances, not misleading, or if any event shall occur or condition exist as a result of which the Time of Sale Information conflicts with the
information contained in the Registration Statement then on file, or if, in the opinion of counsel for the Underwriters, it is necessary to amend or supplement the Time
of Sale Information to comply with applicable law, forthwith to prepare, file with the Commission and furnish, at its own expense, to the Underwriters and to any dealer
upon request, either amendments or supplements to the Time of Sale Information so that the statements in the Time of Sale Information as so amended or supplemented
will not, in the light of the circumstances when the Time of Sale Information is delivered to a prospective purchaser, be misleading or so that the Time of Sale
Information, as amended or supplemented, will no longer conflict with the Registration Statement, or so that the Time of Sale Information, as amended or
supplemented, will comply with applicable law.
(h) If, during such period after the first date of the public offering of the Units as in the opinion of counsel for the Underwriters the Prospectus (or in lieu thereof
the notice referred
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to in Rule 173(a) of the Securities Act) is required by law to be delivered in connection with sales by an Underwriter or dealer, any event shall occur or condition exist
as a result of which it is necessary to amend or supplement the Prospectus in order to make the statements therein, in the light of the circumstances when the Prospectus
(or in lieu thereof the notice referred to in Rule 173(a) of the Securities Act) is delivered to a purchaser, not misleading, or if, in the opinion of counsel for the
Underwriters, it is necessary to amend or supplement the Prospectus to comply with applicable law, forthwith to prepare, file with the Commission and furnish, at its
own expense, to the Underwriters and to the dealers (whose names and addresses you will furnish to the Company) to which Units may have been sold by you on behalf
of the Underwriters and to any other dealers upon request, either amendments or supplements to the Prospectus so that the statements in the Prospectus as so amended
or supplemented will not, in the light of the circumstances when the Prospectus (or in lieu thereof the notice referred to in Rule 173(a) of the Securities Act) is delivered
to a purchaser, be misleading or so that the Prospectus, as amended or supplemented, will comply with applicable law.
(i) To make generally available to the Trust’s security holders and to you as soon as practicable, but in any event not less than fifteen (15) months after the
effective date of the Registration Statement, an earnings statement, which need not be audited, covering a period of at least twelve months beginning with the first fiscal
quarter of the Trust occurring after the date of this Agreement which shall satisfy the provisions of Section 11(a) of the Securities Act and the rules and regulations of
the Commission thereunder.
(j) To comply in all material respects with all applicable securities and other laws, rules and regulations in each jurisdiction in which the Directed Units are
offered in connection with the Directed Unit Program.
(k) To use its reasonable best efforts to cause the Units to be listed on the NYSE and to maintain the listing of the Units on the NYSE. The Trust and the
Company will timely file with the NYSE all documents and notices required by the NYSE of trusts that have or will issue securities that are traded on the NYSE.
(l) Not to, and to cause its affiliates not to, take, directly or indirectly, any action designed, or which will constitute, or has constituted, or might reasonably be
expected to cause or result in the stabilization or manipulation of the price of any security of the Trust to facilitate the sale or resale of the Units.
(m) Prior to each Closing Date, to issue no press release or other communication directly or indirectly and hold no press conferences with respect to the Trust,
the financial condition, results of operations, business, properties, assets or liabilities of the Trust, or the offering of the Units, without your prior consent, which shall
not be unreasonably withheld, conditioned or delayed.
(n) Not, at any time at or after the execution of this Agreement, to directly or indirectly, offer or sell any Units by means of any “prospectus” (within the
meaning of the Securities Act), or use any “prospectus” (within the meaning of the Securities Act) in connection with the offer or sale of the Units, in each case other
than the Time of Sale Information and the Prospectus.
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(o) To furnish to you as early as practicable prior to each Closing Date, but not later than two business days prior thereto, a copy of the latest available
unaudited interim and monthly consolidated financial statements, if any, of the Trust which have been read by the Trust’s independent registered public
accountants, as stated in their letter to be furnished pursuant to Section 8(k) hereof.
(p) To apply the net proceeds from the sale of the Units in the manner set forth under the caption “Use of Proceeds” in the Time of Sale Information and the
Prospectus; and to file with the Commission such information on Form 10-Q or Form 10-K as may be required by Rule 463 under the Securities Act.
(q) To comply with all provisions of any undertakings contained in the Registration Statement.
(r) To file promptly all reports and documents and any preliminary or definitive proxy or information statement required to be filed by the Trust with the
Commission in order to comply with the Exchange Act for so long as a prospectus is required by the Securities Act to be delivered (whether physically or through
compliance with Rule 172 under the Securities Act or any similar rule) in connection with any sale of the Units.
(s) Not more than three days following the Initial Closing Date, the Company will record the Conveyances Documents in the Recorder of Deeds in the Register
and Recorders offices of Washita County, Oklahoma. The Company will provide to the Underwriters evidence of such filings reasonably satisfactory to counsel for the
Underwriters as promptly as practicable following the time of such filings, and in any event not more than 30 days following the Initial Closing Date.
(t) On each Closing Date, all stock transfer, stamp duties and other taxes (other than income taxes) that are required to be paid in connection with the sale and
transfer of the Units to be sold by the Trust to the Underwriters or otherwise in connection with the performance of the Trust’s obligations hereunder will have been
fully paid for by the Trust and all laws imposing such taxes will have been fully complied with.
(u) In order to document the Underwriters’ compliance with the Code, with respect to the transactions herein contemplated, the Company shall deliver to you at
or prior to the Initial Closing Date a properly completed and executed United States Treasury Department Form W-9 (or an appropriate substitute form).
(v) The Trust will engage and maintain, at its expense, a transfer agent and, if necessary under the jurisdiction of its organization or the rules of any national
securities exchange on which the Common Units will be listed, a registrar (which, if permitted by applicable laws and rules may be the same entity as the transfer agent)
for the Common Units.
(w) The Trust will furnish to holders of the Common Units as soon as practicable after the end of each fiscal year an annual report (including financial
statements of the Trust certified by independent public accountants) and, as soon as practicable after the end of each of the first three quarters of each fiscal year
(beginning with the first full fiscal quarter ending after the effective date of the Registration Statement), to make available to holders of the Common Units
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summary financial information of the Trust for such quarter in reasonable detail. For purposes of this Section 5(w), the Trust shall be deemed to have made available
such summary financial information if such information has been filed on EDGAR.
(x) Whether or not the transactions contemplated by this Agreement are consummated or this Agreement is terminated, to pay or cause to be paid all expenses
incident to the performance of its obligations under this Agreement, including: (i) the fees, disbursements and expenses of the Company’s and the Trust’s counsel and
the Company’s and the Trust’s accountants in connection with the registration and delivery of the Units under the Securities Act and all other fees or expenses in
connection with the preparation and filing of the Registration Statement, any Preliminary Prospectus, the Time of Sale Information, the Pricing Prospectus, the
Prospectus, any Free Writing Prospectus prepared by or on behalf of, used by, or referred to by the Company or the Trust and amendments and supplements to any of
the foregoing, including all printing costs associated therewith, and the mailing and delivering of copies thereof to the Underwriters and dealers, in the quantities
hereinabove specified, (ii) all costs and expenses related to the transfer and delivery of the Units to the Underwriters, including any transfer or other taxes payable
thereon, (iii) the cost of producing any Blue Sky or Legal Investment memorandum in connection with the offer and sale of the Units under state securities laws and all
expenses in connection with the qualification of the Units for offer and sale under state securities laws as provided in Section 6(e) hereof, including filing fees and the
reasonable fees and disbursements of counsel for the Underwriters in connection with such qualification and in connection with the Blue Sky or Legal Investment
memorandum, (iv) any filing for review of the public offering of the Units by FINRA, including the filing fees and up to $20,000 in legal fees of counsel to the
Underwriters relating to FINRA matters, (v) all fees and expenses in connection with the filing and preparation of the Trust’s Registration Statement on Form 8-A
relating to the Common Units and all costs and expenses incident to the listing of the Common Units on the NYSE or any other national stock exchange, (vi) the cost of
printing certificates representing the Units, (vii) the costs and charges of any transfer agent, registrar or depositary, (viii) the costs and expenses of the Company and the
Trust relating to investor presentations on any “road show” undertaken in connection with the marketing of the offering of the Units, including, without limitation,
expenses associated with the preparation or dissemination of any electronic road show, expenses associated with the production of road show slides and graphics, fees
and expenses of any consultants engaged in connection with the road show presentations with the prior approval of the Company, travel and lodging expenses of the
representatives and officers of the Company and any such consultants, and the cost of any aircraft chartered in connection with the road show, (ix) all fees and
disbursements incurred by the Underwriters in connection with the Directed Unit Program and stamp duties, similar taxes or duties or other taxes, if any, incurred by the
Underwriters in connection with the Directed Unit Program and (x) all other costs and expenses incident to the performance of the obligations of the Company and the
Trust hereunder for which provision is not otherwise made in this Section. It is understood, however, that except as provided in this Section 5, Section 6 entitled
“Indemnity and Contribution,” Section 7 entitled “Directed Unit Program Indemnification” and Section 11 entitled “Failure to Comply,” the Underwriters will pay their
costs and expenses, including fees and disbursements of their counsel, transfer taxes payable on resale of any of the Units by them and any advertising expenses
connected with any offers they may make. It is further understood that the Company, and not the Trust, shall be responsible to pay or cause to be paid all expenses
incident to the performance of its obligations under subsections (iv) and (ix) above. Notwithstanding the
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foregoing, the Underwriters shall reimburse the Company for up to $150,000 of the actual out-of-pocket costs and expenses the Company incurs under this Section 5(x)
if the transactions contemplated by this Agreement are consummated.
For a period commencing on the date hereof and ending on the 180th day after the date of the Prospectus (the “Lock-Up Period”), the Company will not, directly
or indirectly, (i) offer, sell, contract to sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in
the disposition by any person at any time in the future of) any Trust Units, or other securities of the Trust, or other securities that are derived from the Subject Interests
(as defined in the Conveyances) that are substantially similar to the Units, or securities convertible into or exchangeable for Trust Units, or sell or grant options, rights
or warrants with respect to any Trust Units, or securities convertible into or exchangeable for Trust Units (collectively, “ Trust Securities ”), (ii) enter into any swaps or
other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such units, whether any such transaction
is to be settled by delivery of Trust Units or other securities, in cash or otherwise, (iii) file or cause to be filed a registration statement, including any amendments, with
respect to the registration of any Trust Securities or (iv) publicly disclose the intention to do any of the foregoing, in each case without the prior written consent of the
Representatives on behalf of the Underwriters; notwithstanding the foregoing if (x) during the last 17 days of the Lock-Up Period, the Trust issues an earnings release
or announces material news or a material event relating to the Trust occurs or (y) prior to the expiration of the Lock-Up Period, the Trust announces that it will release
earnings results during the 16-day period beginning on the last day of the Lock-Up Period, then the restriction imposed in this Section 5(y) shall continue to apply until
the expiration of the 18-day period beginning on the date of the issuance of the earnings release, announcement of earnings or the announcement of the material news or
the occurrence of the material event, unless the Representatives, on behalf of the Underwriters, waive such extension in writing. The Company and the Trust shall
promptly notify the Representatives of any earnings release, news or event that may give rise to an extension of the Lock-Up Period.
6. Indemnity and Contribution.
(a) The Company and the Trust agree, jointly and severally, to indemnify and hold harmless each Underwriter, its partners, members, directors, employees and
officers, its agents who participated in the distribution of the Units and each person, if any, who controls any Underwriter within the meaning of either Section 15 of the
Securities Act or Section 20 of the Exchange Act and each affiliate of any Underwriter within the meaning of Rule 405 under the Securities Act from and against any
and all losses, claims, damages and liabilities, including, without limitation, any reasonable legal or other expenses incurred in connection with defending or
investigating any such action or claim (collectively, “ Damages ”) arising out of or based upon any untrue statement or alleged untrue statement of a material fact
contained in the Registration Statement or any amendment thereof, any Preliminary Prospectus, the Time of Sale Information, any Issuer Free Writing Prospectus, any
Company or Trust information that the Company or the Trust, respectively, has filed, or is required to file, pursuant to Rule 433(d) under the Securities Act, or the
Prospectus or any amendment or supplement thereto, or caused by any omission or alleged omission to state therein a material fact required to be stated therein or
necessary to make the statements therein (in the case of the Preliminary Prospectus, the Time of Sale Information,
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any Issuer Free Writing Prospectus or the Prospectus or in any amendment or supplement thereto, in the light of the circumstances under which they were made) not
misleading, except insofar as such losses, claims, damages or liabilities are caused by any such untrue statement or omission or alleged untrue statement or omission
based upon information relating to any Underwriter furnished to the Company or the Trust in writing by such Underwriter through you expressly for use therein.
(b) Each Underwriter agrees, severally and not jointly, to indemnify and hold harmless the Company and the Trust, their respective trustees, directors, officers
who sign the Registration Statement and each person, if any, who controls the Company or the Trust within the meaning of either Section 15 of the Securities Act or
Section 20 of the Exchange Act to the same extent as the foregoing indemnity from the Company and Trust to such Underwriter, but only with reference to information
relating to such Underwriter furnished to the Company or the Trust in writing by such Underwriter expressly for use in the Registration Statement, any Preliminary
Prospectus, the Time of Sale Information, any Issuer Free Writing Prospectus or the Prospectus or any amendment or supplement thereto, which information consists
solely of the following information in the Preliminary Prospectus and the Prospectus: the third, sixth, ninth and tenth paragraphs under “Underwriting.”
(c) In case any proceeding (including any governmental investigation) shall be instituted involving any person in respect of which indemnity may be sought
pursuant to Section 6(a) or 6(b), such person (the “ indemnified party ”) shall promptly notify the person against whom such indemnity may be sought (the “
indemnifying party ”) in writing and the indemnifying party, upon request of the indemnified party, shall retain counsel reasonably satisfactory to the indemnified party
to represent the indemnified party and any others the indemnifying party may designate in such proceeding and shall pay the fees and disbursements of such counsel
related to such proceeding. In any such proceeding, any indemnified party shall have the right to retain its own counsel, but the fees and expenses of such counsel shall
be at the expense of such indemnified party unless (a) the indemnifying party and the indemnified party shall have mutually agreed to the retention of such counsel or
(b) the named parties to any such proceeding (including any impleaded parties) include both the indemnifying party and the indemnified party and representation of
both parties by the same counsel would be inappropriate due to actual or potential differing interests between them. It is understood that the indemnifying party shall
not, in respect of the legal expenses of any indemnified party in connection with any proceeding or related proceedings in the same jurisdiction, be liable for the fees
and expenses of more than one separate firm (in addition to any local counsel) for all such indemnified parties and that all such fees and expenses shall be reimbursed as
they are incurred. Such firm shall be designated in writing by the Representatives, in the case of parties indemnified pursuant to Section 6(a), and by the Company or
the Trust, as applicable, in the case of parties indemnified pursuant to Section 6(b). The indemnifying party shall not be liable for any settlement of any proceeding
effected without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the indemnifying party agrees to indemnify the
indemnified party from and against any loss or liability by reason of such settlement or judgment, but in the case of a judgment only to the extent stated in Sections 6(a)
and 6(b). Notwithstanding the foregoing sentence, if at any time an indemnified party shall have requested an indemnifying party to reimburse the indemnified party for
fees and expenses of counsel as contemplated by the second and third sentences of this paragraph, the indemnifying party agrees that it shall be liable for any
33
settlement of any proceeding effected without its written consent if (i) such settlement is entered into more than 30 days after receipt by such indemnifying party of the
aforesaid request and (ii) such indemnifying party shall not have reimbursed the indemnified party in accordance with such request prior to the date of such settlement.
No indemnifying party shall, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened proceeding in respect of
which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party, unless such settlement includes
an unconditional release of such indemnified party from all liability on claims that are the subject matter of such proceeding.
(d) Notwithstanding the foregoing, the Trust shall not be obligated to make any payments to an indemnified party under this Section 6 until the earlier to occur of
the following: (a) with respect to a final, nonappealable judgment of a court of competent jurisdiction or a settlement agreement, the Company has not paid such
indemnified party the amount owed within 90 days of the due date under such judgment or settlement, (ii) with respect to expenses, the Company has not paid such
indemnified party the amount owed within 90 days of submission by the indemnified party for reimbursement of such expenses or (iii) the Company shall become the
subject of any bankruptcy or insolvency proceedings or publicly declares its inability to pay its debts as they become due.
(e) To the extent the indemnification provided for in Section 6(a) or 6(b) is unavailable to an indemnified party or insufficient in respect of any losses, claims,
damages or liabilities referred to therein, then each indemnifying party under such paragraph, in lieu of indemnifying such indemnified party thereunder, shall
contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (i) in such proportion as is appropriate to
reflect the relative benefits received by the Company and the Trust, respectively, on the one hand and the Underwriters on the other hand from the offering of the Units
or (ii) if the allocation provided by clause 6(e)(i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits
referred to in clause 6(e)(i) above but also the relative fault of the Company and the Trust on the one hand and of the Underwriters on the other hand in connection with
the statements or omissions that resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations. The relative benefits
received by the Company and the Trust on the one hand and the Underwriters on the other hand in connection with the offering of the Units shall be deemed to be in the
same respective proportions as the net proceeds from the offering (after deducting underwriting discounts and commissions but before deducting expenses) received by
the Trust (which amount, for purposes of this Section 6(e), shall also be deemed received by the Company without duplication), and the total underwriting discounts and
commissions received by the Underwriters, in each case as set forth in the table on the cover of the Prospectus, bear to the aggregate Public Offering Price of the Units;
provided that, in the event that the Underwriters shall have purchased any Additional Units hereunder, any determination of the relative benefits received by the
Company and the Trust on the one hand or the Underwriters on the other hand from the offering of the Units shall include the net proceeds (after deducting
underwriting discounts and commissions but before deducting expenses) received by the Trust (which amount, for purposes of this Section 6(e), shall also be deemed
received by the Company without duplication), and the underwriting discounts and commissions received by the Underwriters, from the sale of such Additional Units,
in each case computed on the basis of the respective
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amounts set forth in the second table in the section of the Prospectus entitled “Underwriting.” The relative fault of the Company or the Trust on the one hand and the
Underwriters on the other hand shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the
omission or alleged omission to state a material fact relates to information supplied by the Company or the Trust, on the one hand, or by the Underwriters, on the other
hand, and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The Underwriters’ respective
obligations to contribute pursuant to this Section 6 are several in proportion to the respective number of Units they have purchased hereunder, and not joint.
(f) The Company, the Trust and the Underwriters agree that it would not be just or equitable if contribution pursuant to this Section 6 were determined by pro
rata allocation (even if the Underwriters were treated as one entity for such purpose) or by any other method of allocation that does not take account of the equitable
considerations referred to in Section 6(e). The amount paid or payable by an indemnified party as a result of the losses, claims, damages and liabilities referred to in
Section 6(e) shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by such indemnified party in
connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 6, no Underwriter shall be required to contribute
any amount in excess of the amount by which the total price at which the Units underwritten by it and distributed to the public were offered to the public exceeds the
amount of any damages that such Underwriter has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission.
No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any person who was
not guilty of such fraudulent misrepresentation. The remedies provided for in this Section 6 are not exclusive and shall not limit any rights or remedies which may
otherwise be available to any indemnified party at law or in equity.
(g) The indemnity and contribution provisions contained in this Section 6 and the representations, warranties and other statements of the Company and the Trust
contained in this Agreement shall remain operative and in full force and effect regardless of (a) any termination of this Agreement, (b) any investigation made by or on
behalf of any Underwriter, any of its partners, members, directors or officers, its agents who participated in the distribution of the Units or any person controlling any
Underwriter or any affiliate of any Underwriter or by or on behalf of the Company or the Trust, their respective trustees, officers or directors or any person controlling
the Company or the Trust and (c) acceptance of and payment for any of the Units.
7. Directed Unit Program Indemnification.
(a) The Company agrees to indemnify and hold harmless Morgan Stanley, each person, if any, who controls Morgan Stanley within the meaning of either
Section 15 of the Securities Act or Section 20 of the Exchange Act and each affiliate of Morgan Stanley within the meaning of Rule 405 of the Securities Act (“
Morgan Stanley Entities ”) from and against any and all Damages (i) caused by any untrue statement or alleged untrue statement of a material fact contained in any
material prepared by or with the consent of the Company or the Trust for distribution to Directed Unit Program Participants in connection with the Directed Unit
Program or caused by any omission or alleged omission to state therein a material fact required to be
35
stated therein or necessary to make the statements therein not misleading; (ii) caused by the failure of any Directed Unit Program Participant to pay for and accept
delivery of Directed Units that the Directed Unit Program Participant agreed to purchase; or (iii) related to, arising out of, or in connection with the Directed Unit
Program, other than losses, claims, damages or liabilities (or expenses relating thereto) that are finally judicially determined to have resulted from the bad faith or gross
negligence of Morgan Stanley Entities.
(b) In case any proceeding (including any governmental investigation) shall be instituted involving any Morgan Stanley Entity in respect of which indemnity
may be sought pursuant to Section 7, the Morgan Stanley Entity seeking indemnity, shall promptly notify the Company in writing and the Company, upon request of the
Morgan Stanley Entity, shall retain counsel reasonably satisfactory to the Morgan Stanley Entity to represent the Morgan Stanley Entity and any others the Company
may designate in such proceeding and shall pay the fees and disbursements of such counsel related to such proceeding. In any such proceeding, any Morgan Stanley
Entity shall have the right to retain its own counsel, but the fees and expenses of such counsel shall be at the expense of such Morgan Stanley Entity unless (i) the
Company shall have agreed to the retention of such counsel or (ii) the named parties to any such proceeding (including any impleaded parties) include the Company and
the Morgan Stanley Entity, and representation of both parties by the same counsel would be inappropriate due to actual or potential differing interests between them.
The Company shall not, in respect of the legal expenses of the Morgan Stanley Entities in connection with any proceeding or related proceedings in the same
jurisdiction, be liable for the fees and expenses of more than one separate firm (in addition to any local counsel) for all Morgan Stanley Entities. Any such separate firm
for the Morgan Stanley Entities shall be designated in writing by Morgan Stanley. The Company shall not be liable for any settlement of any proceeding effected
without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the Company agrees to indemnify the Morgan Stanley
Entities from and against any loss or liability by reason of such settlement or judgment. Notwithstanding the foregoing sentence, if at any time a Morgan Stanley Entity
shall have requested the Company to reimburse it for fees and expenses of counsel as contemplated by the second and third sentences of this paragraph, the Company
agrees that it shall be liable for any settlement of any proceeding effected without its written consent if (i) such settlement is entered into more than 30 days after receipt
by the Company of the aforesaid request and (ii) the Company shall not have reimbursed the Morgan Stanley Entity in accordance with such request prior to the date of
such settlement. The Company shall not, without the prior written consent of Morgan Stanley, effect any settlement of any pending or threatened proceeding in respect
of which any Morgan Stanley Entity is or could have been a party and indemnity could have been sought hereunder by such Morgan Stanley Entity, unless such
settlement includes an unconditional release of the Morgan Stanley Entities from all liability on claims that are the subject matter of such proceeding.
(c) To the extent the indemnification provided for in Section 7(a) is unavailable to a Morgan Stanley Entity or insufficient in respect of any losses, claims,
damages or liabilities referred to therein, then the Company in lieu of indemnifying the Morgan Stanley Entity thereunder, shall contribute to the amount paid or
payable by the Morgan Stanley Entity as a result of such losses, claims, damages or liabilities (i) in such proportion as is appropriate to reflect the relative benefits
received by the Company on the one hand and the Morgan Stanley Entities on the other hand from the offering of the Directed Units or (ii) if the allocation provided
36
by clause 7(c)(i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause 7(c)(i) above
but also the relative fault of the Company on the one hand and of the Morgan Stanley Entities on the other hand in connection with any statements or omissions that
resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations. The relative benefits received by the Company on the one
hand and the Morgan Stanley Entities on the other hand in connection with the offering of the Directed Units shall be deemed to be in the same respective proportions
as the net proceeds from the offering of the Directed Units (after deducting underwriting discounts and commissions but before deducting expenses) and the total
underwriting discounts and commissions received by the Morgan Stanley Entities for the Directed Units, bear to the aggregate Public Offering Price of the Directed
Units. If the loss, claim, damage or liability is caused by an untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material
fact, the relative fault of the Company on the one hand and the Morgan Stanley Entities on the other hand shall be determined by reference to, among other things,
whether the untrue or alleged untrue statement or the omission or alleged omission relates to information supplied by the Company or by the Morgan Stanley Entities
and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.
(d) The Company and the Morgan Stanley Entities agree that it would not be just or equitable if contribution pursuant to this Section 7 were determined by pro
rata allocation (even if the Morgan Stanley Entities were treated as one entity for such purpose) or by any other method of allocation that does not take account of the
equitable considerations referred to in Section 7(c). The amount paid or payable by the Morgan Stanley Entities as a result of the losses, claims, damages and liabilities
referred to in the immediately preceding paragraph shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred
by the Morgan Stanley Entities in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 7, no Morgan
Stanley Entity shall be required to contribute any amount in excess of the amount by which the total price at which the Directed Units distributed to the public were
offered to the public exceeds the amount of any damages that such Morgan Stanley Entity has otherwise been required to pay. The remedies provided for in this
Section 7 are not exclusive and shall not limit any rights or remedies which may otherwise be available to any indemnified party at law or in equity.
(e) The indemnity and contribution provisions contained in this Section 7 shall remain operative and in full force and effect regardless of (i) any termination of
this Agreement, (ii) any investigation made by or on behalf of any Morgan Stanley Entity, the Company, its officers or directors or any person controlling the Company,
or the Trust, its trustee or any person controlling the Trust, and (iii) acceptance of and payment for any of the Directed Units.
8. Conditions of Underwriters’ Obligations. The several obligations of the Underwriters to purchase the Firm Units and Additional Units hereunder are subject
to the following conditions:
(a) The Registration Statement shall have become effective not later than [4:00 p.m.], New York City time, on the date hereof, or at such later date and
time as shall be consented to in writing by the Representatives, and all filings required by Rules 424(b), 430A and 462 under the Securities Act shall have been timely
made.
37
(b) All corporate proceedings and other legal matters incident to the authorization, form and validity of the Operative Agreements, and all
other legal matters relating to this Agreement and the Transactions shall be reasonably satisfactory in all material respects to counsel for the Underwriters.
(c) Subsequent to the execution and delivery of this Agreement and prior to each Closing Date:
(i) there shall not have occurred any downgrading, nor shall any notice have been given of any intended or potential downgrading or of any review for a
possible change that does not indicate the direction of the possible change, in the rating accorded any of the securities of the Company or any of its subsidiaries or
the Trust by any “nationally recognized statistical rating organization,” as such term is defined for purposes of Rule 436(g)(2) under the Securities Act; and
(ii) there shall not have occurred any change, or any development involving a prospective change, in the condition, financial or otherwise, or in the earnings,
business or operations of the Company and its subsidiaries, taken as a whole, or the Trust from that set forth in the Time of Sale Information that, in your judgment,
is material and adverse and that makes it, in your judgment, impracticable to market the Units on the terms and in the manner contemplated in the Time of Sale
Information.
(d) You shall have received on each Closing Date a certificate, dated such Closing Date and signed by the chief executive officer or chief financial officer
of the Company,
(i) confirming Section 8(c) above;
(ii) to the effect that the representations and warranties of the Company contained in this Agreement are true and correct as of the Initial Closing Date and that
the Company has complied with all of the agreements and satisfied all of the conditions on its part to be performed or satisfied hereunder on or before such Closing
Date;
(iii) confirming Section 8(m) below; and
(iv) certifying that such officer has carefully examined the Registration Statement, the Time of Sale Information and the Prospectus, as well as each electronic
road show used in connection with the offering of the Units, and, in his opinion (A) the Registration Statement, as of the Effective Date, (B) the Prospectus, as of its
date and on such Closing Date, and (C) the Time of Sale Information, as of the Time of Sale, did not contain any untrue statement of a material fact and did not omit
to state a material fact required to be stated therein (in the case of the Registration Statement) or necessary in order to make the statements therein (except in the case
of the Registration Statement, in the light of the circumstances under which they were made) not misleading.
38
(e) You shall have received on each Closing Date a certificate of the Trustee, dated such Closing Date, executed by a duly authorized
officer of the Trustee, representing and warranting to each of the Underwriters that:
(i) The Trustee is a national banking association authorized and empowered to act as trustee of the Trust pursuant to the Trust Agreement, and no consent,
approval, authorization or filing is required under any law, rule or regulation of the State of Delaware or of the United States of America in order to permit the
Trustee to act as trustee of the Trust; and
(ii) the representations and warranties of the Trust contained in this Agreement are true and correct as of such Closing Date and that the Trust has complied
with all of the agreements and satisfied all of the conditions on its part to be performed or satisfied hereunder on or before such Closing Date, in each case, in all
material respects.
(f) You shall have received on each Closing Date an opinion of Bracewell & Giuliani LLP, counsel to the Company, dated such Closing Date,
substantially in the form of Exhibit A hereto.
(g) You shall have received on each Closing Date an opinion of the Commercial Law Group, P.C., Oklahoma counsel to the Company, dated such
Closing Date, substantially in the form of Exhibit B hereto.
(h) You shall have received on each Closing Date an opinion of Richards, Layton & Finger, P.A., special Delaware counsel to the Trust, dated such
Closing Date, substantially in the form of Exhibit C hereto.
(i) You shall have received on each Closing Date an opinion of Andrews Kurth LLP, counsel to the Trust, dated such Closing Date, substantially in the
form of Exhibit D hereto.
(j) You shall have received on each Closing Date an opinion of Henry Hood, Esq., counsel to the Company, dated such Closing Date, substantially in the
form of Exhibit E hereto.
(k) You shall have received on each Closing Date an opinion of Baker Botts L.L.P., as counsel for the Underwriters, dated such Closing Date, with
respect to such matters as you may reasonably request, and the Company, the Trust and their respective counsel shall have furnished to your counsel such documents as
they may reasonably request for the purpose of enabling them to pass upon such matters.
(l) You shall have received, on each of the date hereof and each Closing Date, a letter dated the date hereof or such Closing Date, respectively, in form
and substance satisfactory to the Underwriters, from PricewaterhouseCoopers LLP, independent public accountants of the Trust and the Company, respectively,
containing statements and information
39
of the type ordinarily included in accountants’ “comfort letters” to underwriters with respect to the financial statements and certain financial information for the Trust
and the Company contained in the Registration Statement, the Time of Sale Information and the Prospectus; provided that the letter delivered on the date hereof shall
use a “cut-off date” not earlier than three business days prior to the date hereof, and the letter delivered on each Closing Date shall use a “cut-off date” not later than the
two business days prior to the date thereof.
(m) You shall have received, on the date hereof, and each Closing Date, letters dated the date hereof, or such Closing Date, respectively, in form and
substance satisfactory to the Underwriters, from Ryder Scott Company, L.P. in its role as the Trust Independent Reserve Engineer, confirming the conclusions and
findings of such firm with respect to the oil and natural gas reserves of the Underlying Properties and the Subject Interests contained in the Registration Statement, the
Time of Sale Information and the Prospectus, and containing statements and information of the type ordinarily included in reserve engineers’ “comfort letters” to
underwriters.
(n) No stop order suspending the effectiveness of the Registration Statement shall have been issued by the Commission and no proceedings for that
purpose shall be pending or, to the knowledge of the Company or the Trust, shall be threatened or contemplated by the Commission at or prior to each Closing Date;
(ii) no order suspending the effectiveness of the Registration Statement or the qualification or registration of the Units under the securities or Blue Sky laws of any
jurisdiction shall be in effect and no proceeding for such purpose shall be pending or, to the knowledge of the Company or the Trust, threatened or contemplated by the
authorities of any jurisdiction; (iii) any request for additional information on the part of the staff of the Commission or any such authorities shall have been complied
with to the satisfaction of the staff of the Commission or such authorities; and (iv) after the date hereof, no amendment or supplement to the Registration Statement or
the Prospectus or any Issuer Free Writing Prospectus shall have been filed unless a copy thereof was first furnished to you and the Company or the Trust obtained your
consent prior to filing with the Commission.
(o) At or prior to the effective date of the Registration Statement, you shall have received a letter from FINRA confirming that FINRA has determined to
raise no objections with respect to the fairness or reasonableness of the underwriting terms and arrangements of the offering contemplated hereby.
(p) The Company and the Trust shall have furnished or caused to have been furnished to you such further certificates and documents as you shall have
reasonably requested.
All such opinions, certificates, letters and other documents will be in compliance with the provisions hereof only if they are reasonably satisfactory in form and
substance to you and your counsel.
The several obligations of the Underwriters to purchase Additional Units hereunder are subject to the satisfaction on and as of the Additional Closing Date of the
conditions set forth in this Section 8, except that, if the Additional Closing Date is other than the Initial Closing Date, the certificates, opinions and letters referred to in
this Section 8 shall be dated as of the Additional Closing Date and the opinions called for by paragraphs (f), (g), (h), (i), (j) and (k) shall be revised to reflect the sale of
Additional Units.
40
If any of the conditions hereinabove provided for in this Section 8 shall not have been satisfied when and as required by this Agreement, this Agreement
may be terminated by you by notifying the Company and the Trust of such termination in writing at or prior to such Closing Date, but you shall be entitled to
waive any of such conditions.
9. Termination. The Underwriters may terminate this Agreement by notice given by you to the Company and the Trust, if after the execution and delivery of this
Agreement and prior to the Initial Closing Date (i) trading generally shall have been suspended or materially limited on any of the New York Stock Exchange or the
NASDAQ Global Market or minimum or maximum prices shall have been generally established on such exchange, or additional material governmental restrictions, not
in force on the date of this Agreement, shall have been imposed on trading in securities generally by any such exchange or by order of the Commission or any court or
other governmental authority, (ii) trading of any securities of the Company or the Trust shall have been suspended on any exchange or in any over-the-counter market,
(iii) a material disruption in securities settlement, payment or clearance services in the United States shall have occurred, (iv) any moratorium on commercial banking
activities shall have been declared by Federal or New York State authorities or (v) there shall have occurred any outbreak or escalation of hostilities, or any change in
financial markets or any calamity or crisis that, in your judgment, is material and adverse and which, singly or together with any other event specified in this clause (v),
makes it, in your judgment, impracticable or inadvisable to proceed with the offer, sale or delivery of the Units on the terms and in the manner contemplated in the Time
of Sale Information or the Prospectus.
10. Effectiveness; Defaulting Underwriters. (a) This Agreement shall become effective upon the execution and delivery hereof by the parties hereto.
(b) If, on any Closing Date, any one or more of the Underwriters shall fail or refuse to purchase Units that it has or they have agreed to purchase hereunder on
such date, and the aggregate number of Units which such defaulting Underwriter or Underwriters agreed but failed or refused to purchase is not more than one-tenth of
the aggregate number of the Units to be purchased on such Closing Date, the other Underwriters shall be obligated severally in the proportions that the number of Firm
Units set forth opposite their respective names in Schedule I bears to the aggregate number of Firm Units set forth opposite the names of all such non-defaulting
Underwriters, or in such other proportions as you may specify, to purchase the Units which such defaulting Underwriter or Underwriters agreed but failed or refused to
purchase on such date; provided that in no event shall the number of Units that any Underwriter has agreed to purchase pursuant to this Agreement be increased
pursuant to this Section 10 by an amount in excess of one-ninth of such number of Units without the written consent of such Underwriter. If, on the Initial Closing Date,
any Underwriter or Underwriters shall fail or refuse to purchase Firm Units and the aggregate number of Firm Units with respect to which such default occurs is more
than one-tenth of the aggregate number of Firm Units to be purchased on such date, and arrangements satisfactory to you, the Trust and the Company for the purchase
of such Firm Units are not made within 48 hours after such default, this Agreement shall terminate without liability on the part of any non-defaulting Underwriter, the
Company or the Trust. In
41
any such case either you, the Trust or the Company shall have the right to postpone the Initial Closing Date, but in no event for longer than seven days, in order that the
required changes, if any, in the Registration Statement, in the Time of Sale Information, in the Prospectus or in any other documents or arrangements may be effected.
If, on an Additional Closing Date, any Underwriter or Underwriters shall fail or refuse to purchase Additional Units and the aggregate number of Additional Units with
respect to which such default occurs is more than one-tenth of the aggregate number of Additional Units to be purchased on such Additional Closing Date, the
non-defaulting Underwriters shall have the option to (i) terminate their obligation hereunder to purchase the Additional Units to be sold on such Additional Closing
Date or (ii) purchase not less than the number of Additional Units that such non-defaulting Underwriters would have been obligated to purchase in the absence of such
default. Any action taken under this paragraph shall not relieve any defaulting Underwriter from liability in respect of any default of such Underwriter under this
Agreement.
11. Failure to Comply. If this Agreement shall be terminated by the Underwriters, or any of them, because of any failure or refusal on the part of the Company or
the Trust to comply with the terms or to fulfill any of the conditions of this Agreement, or if for any reason the Company or the Trust shall be unable to perform its
obligations under this Agreement, the Company will reimburse the Underwriters or such Underwriters as have so terminated this Agreement with respect to themselves,
severally, for all out-of-pocket expenses (including the fees and disbursements of their counsel) reasonably incurred by such Underwriters in connection with this
Agreement or the offering contemplated hereunder.
12. Entire Agreement. This Agreement, together with any contemporaneous written agreements and any prior written agreements (to the extent not superseded
by this Agreement) that relate to the offering of the Units, represents the entire agreement between the Company, the Trust and the Underwriters with respect to the
preparation of the Registration Statement, any Preliminary Prospectus, the Time of Sale Information, the Prospectus, the conduct of the offering, and the purchase and
sale of the Units.
13. No Fiduciary Duty. Each of the Company and the Trust acknowledges that in connection with the offering of the Units: (a) the Underwriters have acted at
arms length, are not agents of, and owe no fiduciary duties to, the Company, the Trust or any other person, (b) the Underwriters owe the Company and the Trust only
those duties and obligations set forth in this Agreement and prior written agreements (to the extent not superseded by this Agreement), if any, and (c) the Underwriters
may have interests that differ from those of the Company and the Trust. Each of the Company and the Trust waives to the full extent permitted by applicable law any
claims it may have against the Underwriters arising from an alleged breach of fiduciary duty in connection with the offering of the Units.
14. Counterparts. This Agreement may be signed in two or more counterparts, each of which shall be an original, with the same effect as if the signatures thereto
and hereto were upon the same instrument.
15. Applicable Law. This Agreement shall be governed by and construed in accordance with the internal laws of the State of New York.
42
16. Headings. The headings of the sections of this Agreement have been inserted for convenience of reference only and shall not be deemed a part of this
Agreement.
17. Notices. All communications hereunder shall be in writing and effective only upon receipt and if to the Underwriters shall be delivered, mailed or sent to you
in care of Morgan Stanley & Co. LLC, 1585 Broadway, New York, New York 10036, Attention: Equity Syndicate Desk, with a copy to the Legal Department, and
(ii) Raymond James & Associates, Inc., 880 Carillon Parkway, St. Petersburg, Florida 33716, Attention: John Critchlow; and if to the Company shall be delivered,
mailed or sent to Chesapeake Energy Corporation, 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, Attention: Jennifer M. Grigsby; and if to the Trust
shall be delivered, mailed or sent in care of The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Suite 500, Austin, Texas 78701, Attention:
Michael J. Ulrich.
18. Patriot Act. In accordance with the requirements of the USA Patriot Act, the Underwriters are required to obtain, verify and record information that identifies
their respective clients, including the Company and the Trust, which information may include the name and address of their respective clients, as well as other
information that will allow the Underwriters to properly identify their respective clients.
43
Please confirm that the foregoing correctly sets forth the agreement among the Company, the Trust and the several Underwriters.
Very truly yours,
CHESAPEAKE ENERGY CORPORATION
By:
Name:
Title:
CHESAPEAKE GRANITE WASH TRUST
By:
The Bank of New York Mellon Trust Company,
N.A., as Trustee
By:
Name: Michael J. Ulrich
Title: Vice-President
Signature Page to Underwriting Agreement
CONFIRMED as of the date first above mentioned, on behalf of
the Representatives and the other several Underwriters named in
Schedule I hereto.
MORGAN STANLEY & CO. LLC
By:
Name:
Title:
RAYMOND JAMES & ASSOCIATES, INC.
By:
Name:
Title:
Signature Page to Underwriting Agreement
SCHEDULE I
Number of
Firm Units
Name
Morgan Stanley & Co. LLC.
Raymond James & Associates, Inc.
Deutsche Bank Securities Inc.
Goldman, Sachs & Co.
Wells Fargo Securities, LLC
Barclays Capital Inc.
BNP Paribas Securities Corp.
Citigroup Global Markets Inc.
Credit Agricole Securities (USA) Inc.
Credit Suisse Securities (USA) LLC
Mitsubishi UFJ Securities (USA), Inc.
Mizuho Securities USA Inc.
Natixis Securities Americas LLC
RBS Securities Inc.
Scotia Capital (USA) Inc.
UBS Securities LLC
Comerica Securities, Inc.
Banco Bilbao Vizcaya Argentaria, S.A.
DnB NOR Markets, Inc.
Macquarie Capital (USA) Inc.
Nomura Securities International, Inc.
PNC Capital Markets LLC
SMBC Nikko Capital Markets Limited
SunTrust Robinson Humphrey, Inc.
TD Securities (USA) LLC
Total:
[22,875,000]
I-1
SCHEDULE II
Free Writing Prospectuses
Bona fide electronic roadshow available on [www.netroadshow.com]
II-1
SCHEDULE III
Information Included in “Time of Sale Information”
Title of securities:
Common Units
Total number of units offered:
[22,875,000] Common Units
Public offering price:
$[
Free Writing Prospectuses
[None]
III-1
] per Common Unit
EXHIBIT A
FORM OF OPINION OF BRACEWELL & GIULIANI LLP
1. No consent, approval, authorization or order of, or filing with, any U.S. federal, New York, Delaware or Texas governmental agency or body or any court is
required for (A) the execution, delivery and performance by the Trust and the Chesapeake Entities of the Operative Agreements to which the Trust or any of the
Chesapeake Entities is a party, (B) the issuance and sale of the Offered Securities by the Trust or (C) compliance by the Trust and the Chesapeake Entities with the
terms and provisions of the Operative Agreements to which the Trust or any of the Chesapeake Entities is a party, other than (A) for registration of the Trust Units
under the Securities Act and consents required under the Exchange Act, and applicable state securities or “Blue Sky” laws in the State of Delaware, the State of New
York, the State of Texas or the United States of America in connection with the purchase and distribution of the Units by the Underwriters, as to which counsel need not
provide an opinion, (B) such consents that have been, or prior to the Initial Closing Date will be, obtained or made, or (C) such consents that, if not obtained, would not
reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect or materially impair the ability of the Trust or any of the Chesapeake
Entities to consummate the Transactions.
2. None of (A) the execution, delivery and performance by the Trust and the Chesapeake Entities of the Operative Agreements to which the Trust or any of the
Chesapeake Entities is a party, (B) the issuance and sale of the Offered Securities by the Trust or (C) compliance by the Trust and the Chesapeake Entities with the
terms and provisions of the Operative Agreements to which the Trust or any of the Chesapeake Entities is a party, (1) will result in a violation of U.S. federal laws, the
laws of the State of New York or the State of Texas, the Delaware General Corporation Law, the Delaware Limited Liability Company Act or the Delaware Limited
Partnership Act, in each case, which are, in our experience, customarily applicable to securities offerings, (2) will result in a violation of any order of any governmental
agency or body or any court having jurisdiction over the Trust or the Chesapeake Entities or any of their respective properties or (3) will result in a breach or violation
of any of the terms and provisions of, or constitute a default under, any of the agreements or instruments filed as an exhibit to the Registration Statement or referenced
as Exhibits 4.1 through 4.12, inclusive, Exhibits 10.1.1 through 10.1.15, inclusive, and Exhibits 10.2.2 through 10.3, inclusive, to the Company’s Annual Report on
Form 10-K for the year ended December 31, 2010; and Exhibits 10.1.14 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30,
2011, to which the Trust or any of the Chesapeake Entities is a party or by which the Trust or any of the Chesapeake Entities is bound or to which any of the properties
of the Trust or the Chesapeake Entities is subject, except in the case of this clause (3) for such breaches, violations or defaults that would not reasonably be expected to
have, individually or in the aggregate, a Material Adverse Effect or materially impair the ability of the Trust or any of the Chesapeake Entities to consummate the
Transactions; provided , however , we express no opinion in this paragraph (ii) with respect to compliance with the anti-fraud provisions of federal or state securities
laws, rules or regulations or any other state or federal anti-fraud statute, rule or regulation.
A-1
3. Assuming the due authorization, execution and delivery by the parties thereto, the Registration Rights Agreement and the Administrative Services
Agreement constitute valid and legally binding agreements of the parties thereto, enforceable against each of them in accordance with its respective terms,
subject to applicable bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws relating to or affecting creditors’ rights generally
and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).
4. The statements set forth in the Registration Statement, the Time of Sale Information and the Prospectus under the captions “The Trust,” “Description of the
Royalty Interests,” “Description of the Trust Agreement,” “Description of the Trust Units,” “U.S. Federal Income Tax Considerations,” “ERISA Considerations,” and
“The Underlying Properties—Regulation,” insofar as they purport to constitute summaries of provisions of federal statutes, rules and regulations, or of any specific
agreement or instrument, constitute complete and accurate summaries thereof in all material respects; and the descriptions of the Offered Securities contained in the
Registration Statement, the Time of Sale Information and the Prospectus under the captions “The Trust,” “Description of the Trust Agreement” and “Description of the
Trust Units” constitute accurate summaries as to legal matters of the terms of the Offered Securities in all material respects.
5. To our knowledge, neither the filing of the Registration Statement nor the offering or sale of the Offered Securities as contemplated by the Underwriting
Agreement gives rise to any rights for or relating to the registration of any Offered Securities or other securities of the Trust.
6. The Registration Statement was declared effective under the Securities Act as of [__], 2011; to our knowledge, no stop order suspending the effectiveness of
the Registration Statement has been issued and no proceedings for that purpose have been instituted or threatened by the Commission; and any required filing of the
Prospectus pursuant to Rule 424(b) under the Securities Act has been made in the manner and within the time period required by such Rule.
7. The Registration Statement, on the most recent Effective Date, and the Prospectus, when filed with the Commission pursuant to Rule 424(b) and as of the date
hereof, appeared on their face to comply as to form, in all material respects, with the requirements of the Securities Act, except that, in each case, we express no opinion
as to (i) any of the documents incorporated by reference in the Registration Statement or (ii) the financial statements and schedules and other financial and accounting
data (including the notes thereto and auditors’ report thereon), the oil and gas reserve and related future net revenue data and the factual statements contained in the
exhibits to the documents incorporated by reference therein, in each case included therein or incorporated by reference therein or excluded therefrom or included in or
excluded from the exhibits to the documents incorporated by reference in the Registration Statement. To our knowledge, there are no contracts or documents of a
character required to be described in the Registration Statement or the Prospectus or to be filed as exhibits to such Registration Statement which are not described and
filed as required.
8. Neither the Trust, the Company nor any of its subsidiaries is, nor after giving effect to the offering and sale of the Offered Securities and the application of the
net proceeds
A-2
from such sale by the Trust, the Company and its subsidiaries, as described in the Registration Statement, the Time of Sale Information and the Prospectus under the
caption “Use of Proceeds,” will be, an “investment company” or a company “controlled by” an “investment company” or an “affiliated person” of, or “promoter” or
“principal underwriter” for, an “investment” company within the meaning of the Investment Company Act of 1940, as amended.
9. The opinion letter of Bracewell & Giuliani LLP that is filed as Exhibit 8.1 to the Registration Statement is confirmed, and the Underwriters may rely upon
such opinion letter as if it were addressed to them.
Whenever an opinion that is based in part on factual matters is made “to our knowledge,” we have relied to the extent we deem appropriate on certificates of
officers (after the discussion of the contents thereof with such officers) of the Company or the Trustee as to the existence or nonexistence of the factual matters upon
which such opinion is predicated. We have no reason to believe, however, that any such certificate is untrue or inaccurate in any material respect.
In rendering the foregoing opinions, we have relied, without independent investigation, upon the opinions to you of Commercial Law Group, P.C., Henry J.
Hood, Richards, Layton & Finger, P.A. and Andrews Kurth LLP dated as of even date herewith. Our opinions are limited in all respects to federal laws of the United
States of America, the laws of the State of New York and the State of Texas, the Delaware General Corporation Law, the Delaware Limited Liability Company Act and
the Delaware Limited Partnership Act and, in reliance upon the opinion of Commercial Law Group, P.C., the laws of the State of Oklahoma. We express no opinion as
to, and for the purposes of the opinions set forth herein, we have conducted no investigation of, the laws of any other jurisdiction. Furthermore, we express no opinion
with respect to (i) any permits to own or operate any real or personal property or (ii) state or local tax statutes to which the Company or the Trust may be subject.
Because the primary purpose of our engagement was not to establish or confirm factual matters or financial or accounting matters and because of the wholly or
partially non-legal character of many of the statements contained in the Registration Statement, the Time of Sale Information and the Prospectus and the documents
incorporated by reference therein, we are not passing upon, have not independently verified and do not assume any responsibility for, the accuracy, completeness or
fairness of the statements contained in the Registration Statement, the Time of Sale Information or the Prospectus or the documents incorporated by reference therein,
except to the extent specified in paragraph (iii) above. Without limiting the foregoing, we assume no responsibility for, have not independently verified and have not
been asked to comment on the accuracy, completeness or fairness of the financial statements and schedules or other financial and accounting data or oil and gas reserve
and future net revenue data included in the Registration Statement, the Time of Sale Information or the Prospectus or the documents incorporated by reference therein,
and we have not examined the accounting, financial or other records from which such financial statements and schedules, other financial and accounting data and oil
and gas reserve and future net revenue data were derived. In addition, we are not experts with respect to any portion of the Registration Statement, the Time of Sale
Information or the Prospectus. However, we have participated in conferences with officers and other representatives of the Trust and the Company, the independent
registered public accounting firm and independent petroleum reserve engineers for the Trust and the Company, your representatives
A-3
and your counsel at which the contents of the Prospectus, the Time of Sale Information and the Registration Statement and related matters were discussed. Based upon
such participation and review, and relying, to the extent we deemed appropriate, as to materiality upon the factual statements of officers and other representatives of the
Trust and the Company and of your representatives, we advise you that no facts have come to our attention that have caused us to believe that (i) any part of the
Registration Statement (other than the financial statements and schedules and other financial or accounting data (including the notes thereto and auditor’s report
thereon), oil and gas reserve and related future net revenue data and the factual statements in the exhibits thereto or to the documents incorporated by reference therein,
in each case included therein or incorporated therein by reference, as to which we have not been asked to comment), at the time such part became effective, contained
an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading, (ii) the
Time of Sale Information (other than the financial statements and schedules and other financial or accounting data (including the notes thereto and auditor’s report
thereon), oil and gas reserve and related future net revenue data and the factual statements in the exhibits to the documents incorporated by reference therein or
incorporated therein by reference, as to which we have not been asked to comment), as of the Time of Sale and as of the date of the Underwriting Agreement, contained
an untrue statement of a material fact or omitted to state a material fact necessary to make the statements therein, in the light of the circumstances under which they
were made, not misleading, (iii) the Prospectus (other than the financial statements and schedules and other financial or accounting data (including the notes thereto and
auditor’s report thereon), oil and gas reserve and related future net revenue data or the factual statements in the exhibits to the documents incorporated by reference
therein, in each case included therein or incorporated therein by reference, as to which we have not been asked to comment), as of its date and as of the date hereof,
included or includes an untrue statement of a material fact or omitted or omits to state a material fact necessary in order to make the statements therein, in the light of
the circumstances under which they were made, not misleading, or (iv) any of the documents incorporated by reference in the Registration Statement (other than the
financial statements and schedules and other financial or accounting data (including the notes thereto and auditor’s report thereon), oil and gas reserve and related future
net revenue data and the factual statements in the exhibits thereto, in each case included therein or incorporated therein by reference, as to which we have not been
asked to comment), at the time such Registration Statement became effective or such document was filed with the Commission (or the time of filing of an amendment,
if so amended or deemed amended), as the case may be, did not comply as to form in all material respects with the requirements of the Securities Act or Exchange Act,
as the case may be.
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EXHIBIT B
FORM OF OPINION OF COMMERCIAL LAW GROUP, P.C.
1. The Company is a corporation duly incorporated and validly existing in good standing under the laws of the State of Oklahoma, with full power and authority
to own, lease and operate its properties and to conduct its business as described in the Registration Statement, the Time of Sale Information and the Prospectus (and any
amendment or supplement thereto).
2. Each of Chesapeake Exploration and Assignee has been duly organized and is in good standing under the laws of the State of Oklahoma, with power and
authority (corporate and other) to own its property and conduct its business as described in the Registration Statement, the Time of Sale Information and the Prospectus;
except where failure to be so qualified would not reasonably be expected to individually or in the aggregate have a Material Adverse Effect; and, to the best of such
counsel’s knowledge, the capital stock or similar equity interests of each of Chesapeake Exploration and Assignee owned by the Company, directly or through
subsidiaries, is owned free from Liens.
3. Each of the Chesapeake Entities has all requisite power and authority to enter into each of the Operative Agreements to which it is a party. Each of the
Operative Agreements to which a Chesapeake Entity is a party has been duly authorized, executed and delivered by the Chesapeake Entity party thereto.
4. The Trustee is not required to qualify to transact business or appoint an agent for service of process in the State of Oklahoma solely as a result of the Trust’s
ownership of the Royalty Interests, and such ownership will not require the appointment of an ancillary trustee in the State of Oklahoma.
5. As of the Initial Closing Date, the Company, directly or through subsidiaries, owns 100% of the outstanding equity interests in Chesapeake Exploration and
Assignee. All of such equity interests have been duly authorized and have been validly issued, and are fully paid and nonassessable.
6. The Term Conveyances have been duly authorized by Chesapeake Exploration and Assignee, and when duly executed by the proper officers, managers or
members of Chesapeake Exploration and Assignee and delivered by Chesapeake Exploration to Assignee, will constitute valid and binding agreements of Chesapeake
Exploration enforceable against Chesapeake Exploration in accordance with their terms, except as such enforceability may be limited by (i) bankruptcy, insolvency,
fraudulent transfer, reorganization, moratorium and similar laws relating to or affecting creditors’ rights generally and by general principles of equity (regardless of
whether such enforceability is considered in a proceeding in equity or at law) and (ii) public policy, applicable law relating to fiduciary duties and indemnification and
an implied covenant of good faith and fair dealing. The forms of the Term Conveyances to be filed are adequate and sufficient under the laws of the State of Oklahoma
to transfer title to the Term Royalties to the Assignee and are in proper form for recording in the State of Oklahoma. Upon execution and delivery of the Term
Conveyances by Chesapeake Exploration and Assignee and
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recordation thereof in the Office of the County Clerk in Washita County, Oklahoma where the Subject Interests are located, the Term Royalties should be treated as
fully conveyed interests in real property under the laws of the State of Oklahoma. The warranty of title provided in Section 1.05 of the Term Conveyances is valid and
enforceable under the laws of the State of Oklahoma. The recording of the Term Conveyances in the Office of the County Clerk in Washita County, Oklahoma where
the Subject Interests are located will be sufficient to provide Assignee the protections afforded under the recordation laws of the State of Oklahoma and the Term
Conveyances should not constitute executory contracts as such term is used in the federal bankruptcy code. The Company is not required to make any recordings or
filings of the Term Conveyances under the laws of the State of Oklahoma other than those recordings or filings described herein.
7. The Assignment and Conveyance has been duly authorized by Assignee, and, when duly executed by the proper officers, managers or members of the
Assignee and the Trust, and delivered by Assignee to the Trust, will constitute valid and binding agreements of Assignee enforceable against Assignee in accordance
with its terms, except as such enforceability may be limited by (i) bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws relating to or
affecting creditors’ rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and
(ii) public policy, applicable law relating to fiduciary duties and indemnification and an implied covenant of good faith and fair dealing. The form of the Assignment
and Conveyance to be filed is adequate and sufficient under the laws of the State of Oklahoma to transfer title to the Term Royalties to the Trust and are in proper form
for recording in the State of Oklahoma. Upon execution and delivery of the Assignment and Conveyance by Assignee and Trustee and recordation thereof in the Office
of the County Clerk in Washita County, Oklahoma where the Subject Interests are located, the Term Royalties should be treated as fully conveyed interests in real
property under the laws of the State of Oklahoma. The warranty of title provided in Section 1 of the Assignment and Conveyance is valid and enforceable under the
laws of the State of Oklahoma. The recording of the Assignment and Conveyance in the Office of the County Clerk in Washita County, Oklahoma where the Subject
Interests are located will be sufficient to provide the Trust the protections afforded under the recordation laws of the State of Oklahoma and the Assignment and
Conveyance should not constitute an executory contract as such term is used in the federal bankruptcy code. The Company is not required to make any recordings or
filings of the Assignment and Conveyance under the laws of the State of Oklahoma other than those recordings or filings described herein.
8. The Perpetual Conveyances have been duly authorized by Chesapeake Exploration, and, when duly executed by the proper officers, managers or members of
Chesapeake Exploration and the Trust, and delivered by Chesapeake Exploration to the Trust, will constitute valid and binding agreements of Chesapeake Exploration
enforceable against Chesapeake Exploration in accordance with their terms, except as such enforceability may be limited by (i) bankruptcy, insolvency, fraudulent
transfer, reorganization, moratorium and similar laws relating to or affecting creditors’ rights generally and by general principles of equity (regardless of whether such
enforceability is considered in a proceeding in equity or at law) and (ii) public policy, applicable law relating to fiduciary duties and indemnification and an implied
covenant of good faith and fair dealing. The forms of the Perpetual Conveyances to be filed are adequate and sufficient under the laws of the State of Oklahoma to
transfer title to the Perpetual
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Royalties to the Trust and are in proper form for recording in the State of Oklahoma. Upon execution and delivery of the Perpetual Conveyances by Chesapeake
Exploration and Trustee and recordation thereof in the Office of the County Clerk in Washita County, Oklahoma where the Subject Interests are located, the Perpetual
Royalties should be treated as fully conveyed interests in real property under the laws of the State of Oklahoma. The warranty of title provided in Section 1.04 of the
Perpetual Conveyances is valid and enforceable under the laws of the State of Oklahoma. The recording of the Perpetual Conveyances in the Office of the County Clerk
in Washita County, Oklahoma where the Subject Interests are located will be sufficient to provide the Trust the protections afforded under the recordation laws of the
State of Oklahoma and the Perpetual Conveyances should not constitute executory contracts as such term is used in the federal bankruptcy code. The Company is not
required to make any recordings or filings of the Perpetual Conveyances under the laws of the State of Oklahoma other than those recordings or filings described herein.
9. The Drilling Support Mortgage, when filed of record in the real estate records maintained by the County Clerk of Washita County, Oklahoma in which the
properties covered thereby are located, will be effective to create, in favor of the Trust, a valid and enforceable lien on the right, title and interest of Chesapeake
Exploration in and to that portion of the properties covered thereby constituting real property described therein and will be valid and enforceable in accordance with its
terms. The form of the Drilling Support Mortgage complies with the laws of the State of Oklahoma relating to filing and recordation, and the recording of the Drilling
Support Mortgage in the real estate records maintained by the County Clerk of Washita County, Oklahoma will be adequate and legally sufficient under the laws of the
State of Oklahoma for the purposes intended to be accomplished thereby. Once the Drilling Support Mortgage is so filed and recorded, no further or subsequent filing or
refiling will be necessary in the State of Oklahoma in order to continue the existence or perfection of the lien referred to in this paragraph.
10. No approval, authorization, consent or other action by, or filing with, any governmental authority of the State of Oklahoma is required on the part of any
Chesapeake Entity in connection with the (i) offering, issuance or sale by the Trust of the Trust Units as described in the Registration Statement, the Time of Sale
Information and the Prospectus, (ii) the execution, delivery and performance of the Operative Agreements by the Trust or any of the Chesapeake Entities party hereto
and thereto, or (iii) the consummation by the Trust or any of the Chesapeake Entities of the transactions contemplated by the Transaction Documents to which the any
of the Trust and the Chesapeake Entities are a party, other than (A) approvals, authorizations, consents or other actions required under state securities or “Blue Sky”
laws in the State of Oklahoma in connection with the purchase and distribution of the Units by the Underwriters, as to which such counsel need not provide an opinion,
(B) such approvals, authorizations, consents or other actions that have been, or prior to the Initial Closing Date will be, obtained or made or (C) such approvals,
authorizations, consents or other actions that, if not obtained, would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect or
materially impair the ability of the Trust or any of the Chesapeake Entities to consummate the Transactions provided for in the Transaction Documents.
11. None of (i) the offering, issuance and sale of the Trust Units by the Trust, (ii) the execution, delivery and performance by the Trust and the Chesapeake
Entities of the Operative
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Agreements to which the Trust or any of the Chesapeake Entities are a party, or (iii) the consummation by the Trust and any of the Chesapeake Entities of the
Transactions contemplated by the Transaction Documents to which any of the Trust and the Chesapeake Entities are a party (A) conflicts or will conflict with the
organizational documents of the Company, Chesapeake Exploration and Chesapeake Operating, (B) will result in a breach or violation of any of the terms and
provisions of, constitute a default under, or result in the imposition of a lien under, any of the agreements or instruments referenced as Exhibits 3.1.2 through 3.1.5,
inclusive, and Exhibit 10.2.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, or (C) violates or will violate any statute, law or
regulation or any order, judgment, decree or injunction known to such counsel of any Oklahoma court or governmental agency or body directed to any of the Trust or
Chesapeake Entities or any of their respective properties or assets in a proceeding to which any of them or their respective properties or assets is a party or is bound,
except in the case of clauses (B) and (C) for any breach, default or violation that would not reasonably be expected to have a Material Adverse Effect or materially
impair the ability of the Trust and the Chesapeake Entities to consummate the Transactions provided for in the Transaction Documents; provided, however , we
express no opinion with respect to compliance with the provisions of (a) any securities laws, rules or regulations or (b) any anti-fraud statute, rule or regulation of the
State of Oklahoma.
In rendering such opinion, such counsel may (i) rely in respect of matters of fact upon certificates of the Trustee and officers and other employees of the
Chesapeake Entities and upon information obtained from public officials, (ii) assume that all documents submitted to them as originals are authentic, that all copies
submitted to them conform to the originals thereof, and that the signatures on all documents examined by them are genuine, (iii) state that their opinion is limited to the
laws of the State of Oklahoma, (v) state that they express no opinion with respect to (A) any permits to own or operate any real or personal property or (B) state or local
tax statutes to which the Chesapeake Entities or the Trust may be subject, and (vi) with respect to the existence of any Lien for which a financing statement under the
Uniform Commercial Code of any state is on file, such counsel’s opinion is based solely upon such counsel’s review of a specific search of the office of the County
Clerk of Oklahoma County, Oklahoma (each of which shall be as of a date not more than 10 days prior to such Closing Date and shall be provided to counsel to the
Underwriters).
B-4
EXHIBIT C
FORM OF OPINION OF RICHARDS, LAYTON & FINGER, P.A.
1. The Trust has been duly formed and is validly existing in good standing as a statutory trust under the Delaware Statutory Trust Act, 12 Del. C. § 3801, et .
seq . (the “Act”), and all filings required under the laws of the State of Delaware with respect to the formation and valid existence of the Trust as a statutory trust have
been made.
2. Under the Act and the Trust Agreement, the Trust has the trust power and authority to (i) own its property and conduct its business, all as described in the
Time of Sale Information, the Prospectus and the Trust Agreement, and (ii) issue the Trust Units, and to execute, deliver and perform its obligations under the Operative
Agreements to which the Trust is a party (the “Trust Documents”).
3. The Trust Agreement constitutes a legal, valid and binding obligation of the Company, Chesapeake Exploration and the Trustees, and is enforceable against
the Company, Chesapeake Exploration and the Trustees, in accordance with its terms.
4. The Trust Units have been duly authorized for issuance by the Trust and upon issuance will constitute valid and, subject to the qualifications set forth in
paragraph 7 below, fully paid and nonassessable undivided beneficial interests in the assets of the Trust.
5. The Trust Documents have been duly authorized by the Trust.
6. Neither the execution, delivery and performance by the Trust of the Underwriting Agreement (including the issuance of Common Units pursuant thereto) and
the Trust Documents, nor the consummation by the Trust of any of the transactions contemplated thereby, (i) requires the consent or approval of, the withholding of
objection on the part of, the giving of notice to, the filing, registration or qualification with, or the taking of any other action in respect of, any governmental authority or
agency of the State of Delaware, other than the filing of the Certificate of Trust with the Secretary of State of the State of Delaware pursuant to the Trust Agreement, or
(ii) violates the Trust Agreement, the Certificate of Trust or any law, rule or regulation of the State of Delaware applicable to the Trust.
7. Under the Act, the Trust Unitholders, as beneficial owners of the Trust, are entitled to the same limitation of personal liability extended to stockholders of
private corporations for profit organized under the General Corporation Law of the State of Delaware. We note that the Trust Unitholders may be obligated to make
payments as set forth in the Trust Agreement.
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EXHIBIT D
FORM OF OPINION OF ANDREWS KURTH LLP
1. Assuming the due authorization by the Trust of the Operative Agreements to which the Trust is party, the Operative Agreements to which the Trust is party
have been validly executed and delivered by the Trustee.
In rendering such opinion, such counsel may (i) rely in respect of matters of fact upon certificates of the Trustee and upon information obtained from public
officials, (ii) assume that all documents submitted to such counsel as originals are authentic, that all copies submitted to such counsel conform to the originals thereof,
and that the signatures on all documents examined by such counsel are genuine and (iii) state that such opinion is limited to matters governed by the laws of the State of
Delaware, New York and federal law.
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EXHIBIT E
FORM OF OPINION OF HENRY J. HOOD
Subject to the assumptions, qualifications and explanations set forth herein, it is my opinion that there are no legal or governmental proceedings pending or
threatened to which the Trust, the Company or its subsidiaries is a party or to which any of their respective properties is subject that are required to be described in the
Registration Statement, the Time of Sale Information or the Prospectus but are not so described as required by the Securities Act or the Exchange Act.
E-1
Exhibit 5.1
October 18, 2011
Chesapeake Granite Wash Trust
c/o The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue, Suite 500
Austin, Texas 78701
Re:
Chesapeake Granite Wash Trust
Ladies and Gentlemen:
We have acted as special Delaware counsel for Chesapeake Granite Wash Trust, a Delaware statutory trust (the “Trust”), in connection with the matters set forth
herein. At your request, this opinion is being furnished to you.
We have examined and relied upon such records, documents, certificates and other instruments as in our judgment are necessary or appropriate to enable us to
render the opinions expressed below, including the following documents:
(a)
The Certificate of Trust of Trust (the “Certificate of Trust”), as filed with the office of the Secretary of State of the State of Delaware (the
“Secretary of State”) on June 29, 2011;
(b)
The Trust Agreement, dated as of June 29, 2011 among Chesapeake Energy Corporation, an Oklahoma corporation, (the “Company”), The
Corporation Trust Company, a Delaware corporation, as Delaware trustee (the “Delaware Trustee”) and The Bank of New York Mellon Trust
Company, N.A., a national banking association, as trustee (the “Trustee”);
(c)
The Registration Statement of the Trust and the Company on Form S-1 and Form S-3 (File Nos. 333-175395 and 333-175395-01, respectively),
including a preliminary prospectus (the “Prospectus”) relating to 26,306,250
Chesapeake Granite Wash Trust
October 18, 2011
Page 2
common units of the Trust representing beneficial interests in the Trust (each, a “Common Unit” and collectively, the “Common Units”), initially
filed with the Securities and Exchange Commission on July 7, 2011, as amended (the “Registration Statement”);
(d)
A form of Amended and Restated Trust Agreement for the Trust (the “Trust Agreement”), to be entered into among the Company, Chesapeake
Exploration, L.L.C., an Oklahoma limited liability company, the Delaware Trustee and the Trustee, attached as Exhibit 4.2 to the Registration
Statement; and
(e)
A Certificate of Good Standing for the Trust, dated October 13, 2011, obtained from the Secretary of State.
Initially capitalized terms used herein and not otherwise defined are used as defined in the Trust Agreement.
As to various questions of fact material to our opinion, we have relied upon the representations made in the foregoing documents.
With respect to all documents examined by us, we have assumed (i) the authenticity of all documents submitted to us as originals, (ii) the conformity with the
originals of all documents submitted to us as copies or forms, and (iii) the genuineness of all signatures.
For purposes of this opinion, we have assumed (i) that the Trust Agreement and the Certificate of Trust will be in full force and effect and will not be amended,
(ii) the due organization or due formation, as the case may be, and valid existence in good standing of each party to the documents (other than the Trust) examined by us
under the laws of the jurisdiction governing its organization or formation, (iii) the legal capacity of natural persons who are signatories to the documents examined by
us, (iv) that each of the parties to the documents (other than the Trust) examined by us has the power and authority to execute and deliver, and to perform its obligations
under, such documents, (v) the due authorization, execution and delivery by all parties thereto of all documents (other than the Trust) examined by us, (vi) the
registration on the books of the Trust of the identity of each Person to whom a Common Unit is to be issued by the Trust (collectively, the “Common Unit Holders”)
and the payment for such Common Unit, in accordance with the Trust Agreement and as contemplated by the Registration Statement, and (vii) that the Common Units
will be duly issued and sold to the Common Unit Holders in accordance with the Trust Agreement and as contemplated by the Registration Statement. We have not
participated in the preparation of the Registration Statement (except for providing this opinion) or the Prospectus and assume no responsibility for their contents, other
than this opinion.
This opinion is limited to the laws of the State of Delaware (excluding the securities laws of the State of Delaware), and we have not considered and express no
opinion on the laws of any other jurisdiction, including federal laws and rules and regulations relating
Chesapeake Granite Wash Trust
October 18, 2011
Page 3
thereto. Our opinions are rendered only with respect to Delaware laws and rules, regulations and orders thereunder which are currently in effect.
Based upon the foregoing, and upon our examination of such questions of laws and rules, regulations and orders thereunder as we have considered necessary or
appropriate, and subject to the assumptions, qualifications, limitations and exceptions set forth herein, we are of the opinion that:
1. The Trust has been duly formed and is validly existing in good standing as a statutory trust under the Delaware Statutory Trust Act, 12 Del. C. § 3801, et seq
.
2. The Common Units of the Trust, when issued, will represent validly issued, fully paid and nonassessable beneficial interests in the Trust.
3. The Common Unit Holders, as beneficial owners of the Trust, will be entitled to the same limitation of personal liability extended to stockholders of private
corporations for profit organized under the General Corporation Law of the State of Delaware.
We consent to the filing of this opinion with the Securities and Exchange Commission as an exhibit to the Registration Statement. We also hereby consent to the
use of our name under the heading “Legal Matters” in the Prospectus. In giving the foregoing consents, we do not thereby admit that we come within the category of
persons whose consent is required under Section 7 of the Securities Act of 1933, as amended, or the rules and regulations of the Securities and Exchange Commission
thereunder.
Very truly yours,
/s/ Richards, Layton & Finger, P.A.
Exhibit 5.2
[Letterhead of Bracewell & Giuliani LLP]
October 18, 2011
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Re: Registered Offering of Common Units Issued by Chesapeake Granite Wash Trust
Ladies and Gentlemen:
We have acted as special counsel for Chesapeake Energy Corporation, an Oklahoma corporation (the “Company”), in connection with the registration by Chesapeake
Granite Wash Trust, a Delaware statutory trust (the “ Trust ”), under the Securities Act of 1933, as amended (the “ Securities Act ”), of common units representing
beneficial interests in the Trust (the “ Common Units ”), pursuant to the registration statement of the Trust and the Company on Form S-1 and Form S-3 (File Nos.
333-175395 and 333-175395-01, respectively) initially filed with the Securities and Exchange Commission (the “ Commission ”) on July 7, 2011 (such registration
statement, as amended to the date hereof, is herein referred to as the “ Registration Statement ”). We have been asked by the Company to render this opinion.
We have examined originals or copies of (a) the Registration Statement, (b) the Certificate of Trust of the Trust, as filed with the office of the Secretary of State of the
State of Delaware on June 29, 2011 (the “ Certificate of Trust ”), (c) the Trust Agreement of the Trust, dated June 29, 2011, by and among the Company, The Bank of
New York Mellon Trust Company, N.A., as trustee (the “ Trustee ”), and The Corporation Trust Company, as Delaware trustee (the “ Delaware Trustee ”) (the “
Initial Trust Agreement ”), (d) the Amended and Restated Trust Agreement of the Trust, a form of which is filed as an exhibit to the Registration Statement, by and
among the Company, Chesapeake Exploration, L.L.C., an Oklahoma limited liability company and wholly owned subsidiary of the Company (“ Chesapeake
Exploration ”), the Trustee and the Delaware Trustee (the “ Amended and Restated Trust Agreement ” and, together with the Certificate of Trust and the Initial
Trust Agreement, the “ Trust Documents ”), pursuant to which the Common Units will be issued, (e) certain resolutions adopted by the Board of Directors of the
Company and the manager of Chesapeake Exploration and (f) such other documents and records as we have deemed necessary and relevant for the purposes hereof. In
addition, we have relied on certificates of officers of the Company and of public officials and others as to certain matters of fact relating to this opinion and have made
such investigations of law as we have deemed necessary and relevant as a basis hereof. In the course of such examinations and investigations, we have assumed the
genuineness of all signatures, the
Chesapeake Energy Corporation
October 18, 2011
Page 2
authenticity of all documents and records submitted to us as originals, the conformity to original documents and records of all documents and records submitted to us as
copies, and the truthfulness of all statements of fact contained therein. We have assumed further that the Trust has duly authorized the issuance of the Common Units.
We have assumed further that the Trust is a statutory trust duly organized, validly existing and in good standing under the laws of the State of Delaware and has, or will
have, all requisite power, authority and legal right to issue the Common Units under the Amended and Restated Trust Agreement when executed. We also have assumed
the due execution and delivery of the Trust Documents by a duly authorized officer of the Trustee and the Delaware Trustee.
Based on the foregoing and subject to the limitations, assumptions and qualifications set forth herein, and having due regard for such legal considerations as we deem
relevant, we are of the opinion that:
1.
The Company is a corporation validly existing and in good standing under the laws of the State of Oklahoma and has the corporate power and
authority to execute and deliver the Trust Documents and to perform its obligations thereunder.
2.
Chesapeake Exploration is a limited liability company validly existing and in good standing under the laws of the State of Oklahoma and has the
limited liability company power and authority to execute and deliver the Amended and Restated Trust Agreement and to perform its obligations
thereunder.
3.
Each of the Company and Chesapeake Exploration has duly authorized the Trust Documents to which it is a party and the Company has duly
executed and delivered the Initial Trust Agreement.
The foregoing opinion is based on and limited to applicable law of the State of Oklahoma, and we render no opinion with respect to the law of any other jurisdiction.
We hereby consent to the filing of this opinion with the Commission as Exhibit 5.2 to the Registration Statement and to the references to our firm under the heading
“Legal Matters” in the prospectus included in the Registration Statement. In giving such consent, we do not admit that we are in the category of persons whose consent
is required under Section 7 of the Securities Act or the rules and regulations promulgated by the Commission thereunder.
Very truly yours,
/s/ Bracewell & Giuliani LLP
Exhibit 8.1
[Letterhead of Bracewell & Giuliani LLP]
October 18, 2011
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Re: Registered Offering of Common Units Issued by Chesapeake Granite Wash Trust
Ladies and Gentlemen:
We have acted as special counsel for Chesapeake Energy Corporation, an Oklahoma corporation (the “Company”), in connection with the registration by Chesapeake
Granite Wash Trust, a Delaware statutory trust (the “ Trust ”), under the Securities Act of 1933, as amended (the “ Securities Act ”), of common units representing
beneficial interests in the Trust (the “ Common Units ”), pursuant to the registration statement of the Trust and the Company on Form S-1 and Form S-3 (File Nos.
333-175395 and 333-175395-01, respectively) initially filed with the Securities and Exchange Commission on July 7, 2011 (such registration statement, as amended to
the date hereof, is herein referred to as the “ Registration Statement ”).
We have examined originals or copies of the Registration Statement and such other documents and records as we have deemed necessary and relevant for the purposes
hereof. In addition, we have relied on certificates of officers of the company and of public officials and others as to certain matters of fact relating to this opinion and
have made such investigations of law as we have deemed necessary and relevant as a basis hereof. In the course of such examinations and investigations, we have
assumed the genuineness of all signatures, the authenticity of all documents and records submitted to us as originals, the conformity to original documents and records
of all documents and records submitted to us as copies, and the truthfulness of all statements of fact contained therein.
Based on the foregoing, all statements of legal conclusions in the Registration Statement under the caption “U.S. Federal Income Tax Considerations,” unless otherwise
noted, constitute our opinion with respect to the matters set forth therein as of the effective date of the Registration Statement.
Chesapeake Energy Corporation
October 18, 2011
Page 2
We hereby consent to the filing of this opinion with the Securities and Exchange Commission as Exhibit 8.1 to the Registration Statement and to the use of our name
under the caption “Legal Matters” in the prospectus constituting part of the Registration Statement. By giving such consent, we do not admit that we are in the category
of persons whose consent is required under Section 7 of the Securities Act and the rules and regulations thereunder.
Very truly yours,
/s/ Bracewell & Giuliani LLP
Exhibit 10.8
ISDA®
International Swaps and Derivatives Association, Inc.
2002 MASTER AGREEMENT
[Date]
dated as of ………………………………………….
MORGAN STANLEY CAPITAL GROUP INC.
CHESAPEAKE GRANITE WASH TRUST
………………………………………………………………….and ……………………………………………………. have entered and/or anticipate entering into one
or more transactions (each a “Transaction”) that are or will be governed by this 2002 Master Agreement, which includes the schedule (the “Schedule”), and the
documents and other confirming evidence (each a “Confirmation”) exchanged between the parties or otherwise effective for the purpose of confirming or evidencing
those Transactions. This 2002 Master Agreement and the Schedule are together referred to as this “Master Agreement”.
Accordingly, the parties agree as follows:—
1. Interpretation
(a) Definitions. The terms defined in Section 14 and elsewhere in this Master Agreement will have the meanings therein specified for the purpose of this Master
Agreement.
(b) Inconsistency. In the event of any inconsistency between the provisions of the Schedule and the other provisions of this Master Agreement, the Schedule will
prevail. In the event of any inconsistency between the provisions of any Confirmation and this Master Agreement, such Confirmation will prevail for the purpose of the
relevant Transaction.
(c) Single Agreement. All Transactions are entered into in reliance on the fact that this Master Agreement and all Confirmations form a single agreement between the
parties (collectively referred to as this “Agreement”), and the parties would not otherwise enter into any Transactions.
2. Obligations
(a) General Conditions.
(i) Each party will make each payment or delivery specified in each Confirmation to be made by it, subject to the other provisions of this Agreement.
(ii) Payments under this Agreement will be made on the due date for value on that date in the place of the account specified in the relevant Confirmation or otherwise
pursuant to this Agreement, in freely transferable funds and in the manner customary for payments in the required currency. Where settlement is by delivery (that is,
other than by payment), such delivery will be made for receipt on the due date in the manner customary for the relevant obligation unless otherwise specified in the
relevant Confirmation or elsewhere in this Agreement.
Copyright © 2002 by International Swaps and Derivatives Association, Inc.
(iii) Each obligation of each party under Section 2(a)(i) is subject to (1) the condition precedent that no Event of Default or Potential Event of Default with respect to
the other party has occurred and is continuing, (2) the condition precedent that no Early Termination Date in respect of the relevant Transaction has occurred or been
effectively designated and (3) each other condition specified in this Agreement to be a condition precedent for the purpose of this Section 2(a)(iii).
(b) Change of Account. Either party may change its account for receiving a payment or delivery by giving notice to the other party at least five Local Business Days
prior to the Scheduled Settlement Date for the payment or delivery to which such change applies unless such other party gives timely notice of a reasonable objection to
such change.
(c) Netting of Payments. If on any date amounts would otherwise be payable:—
(i) in the same currency; and
(ii) in respect of the same Transaction,
by each party to the other, then, on such date, each party’s obligation to make payment of any such amount will be automatically satisfied and discharged and, if the
aggregate amount that would otherwise have been payable by one party exceeds the aggregate amount that would otherwise have been payable by the other party,
replaced by an obligation upon the party by which the larger aggregate amount would have been payable to pay to the other party the excess of the larger aggregate
amount over the smaller aggregate amount.
The parties may elect in respect of two or more Transactions that a net amount and payment obligation will be determined in respect of all amounts payable on the same
date in the same currency in respect of those Transactions, regardless of whether such amounts are payable in respect of the same Transaction. The election may be
made in the Schedule or any Confirmation by specifying that “Multiple Transaction Payment Netting” applies to the Transactions identified as being subject to the
election (in which case clause (ii) above will not apply to such Transactions). If Multiple Transaction Payment Netting is applicable to Transactions, it will apply to
those Transactions with effect from the starting date specified in the Schedule or such Confirmation, or, if a starting date is not specified in the Schedule or such
Confirmation, the starting date otherwise agreed by the parties in writing. This election may be made separately for different groups of Transactions and will apply
separately to each pairing of Offices through which the parties make and receive payments or deliveries.
(d) Deduction or Withholding for Tax.
(i) Gross-Up. All payments under this Agreement will be made without any deduction or withholding for or on account of any Tax unless such deduction or
withholding is required by any applicable law, as modified by the practice of any relevant governmental revenue authority, then in effect. If a party is so required to
deduct or withhold, then that party (“X”) will—
(1) promptly notify the other party (“Y”) of such requirement;
(2) pay to the relevant authorities the full amount required to be deducted or withheld (including the full amount required to be deducted or withheld from any
additional amount paid by X to Y under this Section 2(d)) promptly upon the earlier of determining that such deduction or withholding is required or receiving notice
that such amount has been assessed against Y;
(3) promptly forward to Y an official receipt (or a certified copy), or other documentation reasonably acceptable to Y, evidencing such payment to such authorities;
and
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(4) if such Tax is an Indemnifiable Tax, pay to Y, in addition to the payment to which Y is otherwise entitled under this Agreement, such additional amount as is
necessary to ensure that the net amount actually received by Y (free and clear of Indemnifiable Taxes, whether assessed against X or Y) will equal the full amount Y
would have received had no such deduction or withholding been required. However, X will not be required to pay any additional amount to Y to the extent that it
would not be required to be paid but for:—
(A) the failure by Y to comply with or perform any agreement contained in Section 4(a)(i), 4(a)(iii) or 4(d); or
(B) the failure of a representation made by Y pursuant to Section 3(f) to be accurate and true unless such failure would not have occurred but for (I) any action
taken by a taxing authority, or brought in a court of competent jurisdiction, after a Transaction is entered into (regardless of whether such action is taken or brought
with respect to a party to this Agreement) or (II) a Change in Tax Law.
(ii) Liability. If:—
(1) X is required by any applicable law, as modified by the practice of any relevant governmental revenue authority, to make any deduction or withholding in respect
of which X would not be required to pay an additional amount to Y under Section 2(d)(i)(4);
(2) X does not so deduct or withhold; and
(3) a liability resulting from such Tax is assessed directly against X,
then, except to the extent Y has satisfied or then satisfies the liability resulting from such Tax, Y will promptly pay to X the amount of such liability (including any
related liability for interest, but including any related liability for penalties only if Y has failed to comply with or perform any agreement contained in Section 4(a)(i),
4(a)(iii) or 4(d)).
3. Representations
Each party makes the representations contained in Sections 3(a), 3(b), 3(c), 3(d), 3(e) and 3(f) and, if specified in the Schedule as applying, 3(g) to the other party
(which representations will be deemed to be repeated by each party on each date on which a Transaction is entered into and, in the case of the representations in
Section 3(f), at all times until the termination of this Agreement). If any “Additional Representation” is specified in the Schedule or any Confirmation as applying, the
party or parties specified for such Additional Representation will make and, if applicable, be deemed to repeat such Additional Representation at the time or times
specified for such Additional Representation.
(a) Basic Representations.
(i) Status. It is duly organised and validly existing under the laws of the jurisdiction of its organization or incorporation and, if relevant under such laws, in good
standing;
(ii) Powers. It has the power to execute this Agreement and any other documentation relating to this Agreement to which it is a party, to deliver this Agreement and
any other documentation relating to this Agreement that it is required by this Agreement to deliver and to perform its obligations under this Agreement and any
obligations it has under any Credit Support Document to which it is a party and has taken all necessary action to authorize such execution, delivery and performance;
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(iii) No Violation or Conflict. Such execution, delivery and performance do not violate or conflict with any law applicable to it, any provision of its constitutional
documents, any order or judgment of any court or other agency of government applicable to it or any of its assets or any contractual restriction binding on or affecting
it or any of its assets;
(iv) Consents. All governmental and other consents that are required to have been obtained by it with respect to this Agreement or any Credit Support Document to
which it is a party have been obtained and are in full force and effect and all conditions of any such consents have been complied with; and
(v) Obligations Binding. Its obligations under this Agreement and any Credit Support Document to which it is a party constitute its legal, valid and binding
obligations, enforceable in accordance with their respective terms (subject to applicable bankruptcy, reorganisation, insolvency, moratorium or similar laws affecting
creditors’ rights generally and subject, as to enforceability, to equitable principles of general application (regardless of whether enforcement is sought in a proceeding
in equity or at law)).
(b) Absence of Certain Events. No Event of Default or Potential Event of Default or, to its knowledge, Termination Event with respect to it has occurred and is
continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Agreement or any Credit Support
Document to which it is a party.
(c) Absence of Litigation. There is not pending or, to its knowledge, threatened against it, any of its Credit Support Providers or any of its applicable Specified Entities
any action, suit or proceeding at law or in equity or before any court, tribunal, governmental body, agency or official or any arbitrator that is likely to affect the legality,
validity or enforceability against it of this Agreement or any Credit Support Document to which it is a party or its ability to perform its obligations under this Agreement
or such Credit Support Document.
(d) Accuracy of Specified Information. All applicable information that is furnished in writing by or on behalf of it to the other party and is identified for the purpose of
this Section 3(d) in the Schedule is, as of the date of the information, true, accurate and complete in every material respect.
(e) Payer Tax Representation. Each representation specified in the Schedule as being made by it for the purpose of this Section 3(e) is accurate and true.
(f) Payee Tax Representations. Each representation specified in the Schedule as being made by it for the purpose of this Section 3(f) is accurate and true.
(g) No Agency. It is entering into this Agreement, including each Transaction, as principal and not as agent of any person or entity.
4. Agreements
Each party agrees with the other that, so long as either party has or may have any obligation under this Agreement or under any Credit Support Document to which it is
a party:—
(a) Furnish Specified Information. It will deliver to the other party or, in certain cases under clause (iii) below, to such government or taxing authority as the other
party reasonably directs:—
(i) any forms, documents or certificates relating to taxation specified in the Schedule or any Confirmation;
(ii) any other documents specified in the Schedule or any Confirmation; and
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(iii) upon reasonable demand by such other party, any form or document that may be required or reasonably requested in writing in order to allow such other party or
its Credit Support Provider to make a payment under this Agreement or any applicable Credit Support Document without any deduction or withholding for or on
account of any Tax or with such deduction or withholding at a reduced rate (so long as the completion, execution or submission of such form or document would not
materially prejudice the legal or commercial position of the party in receipt of such demand), with any such form or document to be accurate and completed in a
manner reasonably satisfactory to such other party and to be executed and to be delivered with any reasonably required certification,
in each case by the date specified in the Schedule or such Confirmation or, if none is specified, as soon as reasonably practicable.
(b) Maintain Authorizations. It will use all reasonable efforts to maintain in full force and effect all consents of any governmental or other authority that are required to
be obtained by it with respect to this Agreement or any Credit Support Document to which it is a party and will use all reasonable efforts to obtain any that may become
necessary in the future.
(c) Comply With Laws. It will comply in all material respects with all applicable laws and orders to which it may be subject if failure so to comply would materially
impair its ability to perform its obligations under this Agreement or any Credit Support Document to which it is a party.
(d) Tax Agreement. It will give notice of any failure of a representation made by it under Section 3(f) to be accurate and true promptly upon learning of such failure.
(e) Payment of Stamp Tax. Subject to Section 11, it will pay any Stamp Tax levied or imposed upon it or in respect of its execution or performance of this Agreement
by a jurisdiction in which it is incorporated, organised, managed and controlled or considered to have its seat, or where an Office through which it is acting for the
purpose of this Agreement is located (“Stamp Tax Jurisdiction”), and will indemnify the other party against any Stamp Tax levied or imposed upon the other party or in
respect of the other party’s execution or performance of this Agreement by any such Stamp Tax Jurisdiction which is not also a Stamp Tax Jurisdiction with respect to
the other party.
5. Events of Default and Termination Events
(a) Events of Default. The occurrence at any time with respect to a party or, if applicable, any Credit Support Provider of such party or any Specified Entity of such
party of any of the following events constitutes (subject to Sections 5(c) and 6(e)(iv)) an event of default (an “Event of Default”) with respect to such party:—
(i) Failure to Pay or Deliver. Failure by the party to make, when due, any payment under this Agreement or delivery under Section 2(a)(i) or 9(h)(i)(2) or (4) required
to be made by it if such failure is not remedied on or before the first Local Business Day in the case of any such payment or the first Local Delivery Day in the case of
any such delivery after, in each case, notice of such failure is given to the party;
(ii) Breach of Agreement; Repudiation of Agreement.
(1) Failure by the party to comply with or perform any agreement or obligation (other than an obligation to make any payment under this Agreement or delivery
under Section 2(a)(i) or 9(h)(i)(2) or (4) or to give notice of a Termination Event or any agreement or obligation under Section 4(a)(i), 4(a)(iii) or 4(d)) to be
complied with or performed by the party in accordance with this Agreement if such failure is not remedied within 30 days after notice of such failure is given to the
party; or
(2) the party disaffirms, disclaims, repudiates or rejects, in whole or in part, or challenges the validity of, this Master Agreement, any Confirmation executed and
delivered by that party or any
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Transaction evidenced by such a Confirmation (or such action is taken by any person or entity appointed or empowered to operate it or act on its behalf);
(iii) Credit Support Default.
(1) Failure by the party or any Credit Support Provider of such party to comply with or perform any agreement or obligation to be complied with or performed by it
in accordance with any Credit Support Document if such failure is continuing after any applicable grace period has elapsed;
(2) the expiration or termination of such Credit Support Document or the failing or ceasing of such Credit Support Document, or any security interest granted by such
party or such Credit Support Provider to the other party pursuant to any such Credit Support Document, to be in full force and effect for the purpose of this
Agreement (in each case other than in accordance with its terms) prior to the satisfaction of all obligations of such party under each Transaction to which such Credit
Support Document relates without the written consent of the other party; or
(3) the party or such Credit Support Provider disaffirms, disclaims, repudiates or rejects, in whole or in part, or challenges the validity of, such Credit Support
Document (or such action is taken by any person or entity appointed or empowered to operate it or act on its behalf);
(iv) Misrepresentation. A representation (other than a representation under Section 3(e) or 3(f)) made or repeated or deemed to have been made or repeated by the
party or any Credit Support Provider of such party in this Agreement or any Credit Support Document proves to have been incorrect or misleading in any material
respect when made or repeated or deemed to have been made or repeated;
(v) Default Under Specified Transaction. The party, any Credit Support Provider of such party or any applicable Specified Entity of such party:—
(l) defaults (other than by failing to make a delivery) under a Specified Transaction or any credit support arrangement relating to a Specified Transaction and, after
giving effect to any applicable notice requirement or grace period, such default results in a liquidation of, an acceleration of obligations under, or an early termination
of, that Specified Transaction;
(2) defaults, after giving effect to any applicable notice requirement or grace period, in making any payment due on the last payment or exchange date of, or any
payment on early termination of, a Specified Transaction (or, if there is no applicable notice requirement or grace period, such default continues for at least one Local
Business Day);
(3) defaults in making any delivery due under (including any delivery due on the last delivery or exchange date of) a Specified Transaction or any credit support
arrangement relating to a Specified Transaction and, after giving effect to any applicable notice requirement or grace period, such default results in a liquidation of,
an acceleration of obligations under, or an early termination of, all transactions outstanding under the documentation applicable to that Specified Transaction; or
(4) disaffirms, disclaims, repudiates or rejects, in whole or in part, or challenges the validity of, a Specified Transaction or any credit support arrangement relating to
a Specified Transaction that is, in either case, confirmed or evidenced by a document or other confirming evidence executed and delivered by that party, Credit
Support Provider or Specified Entity (or such action is taken by any person or entity appointed or empowered to operate it or act on its behalf);
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(vi) Cross-Default. If “Cross-Default” is specified in the Schedule as applying to the party, the occurrence or existence of:—
(l) a default, event of default or other similar condition or event (however described) in respect of such party, any Credit Support Provider of such party or any
applicable Specified Entity of such party under one or more agreements or instruments relating to Specified Indebtedness of any of them (individually or collectively)
where the aggregate principal amount of such agreements or instruments, either alone or together with the amount, if any, referred to in clause (2) below, is not less
than the applicable Threshold Amount (as specified in the Schedule) which has resulted in such Specified Indebtedness becoming, or becoming capable at such time
of being declared, due and payable under such agreements or instruments before it would otherwise have been due and payable; or
(2) a default by such party, such Credit Support Provider or such Specified Entity (individually or collectively) in making one or more payments under such
agreements or instruments on the due date for payment (after giving effect to any applicable notice requirement or grace period) in an aggregate amount, either alone
or together with the amount, if any, referred to in clause (1) above, of not less than the applicable Threshold Amount;
(vii) Bankruptcy. The party, any Credit Support Provider of such party or any applicable Specified Entity of such party:—
(l) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (2) becomes insolvent or is unable to pay its debts or fails or admits in writing its
inability generally to pay its debts as they become due; (3) makes a general assignment, arrangement or composition with or for the benefit of its creditors;
(4)(A) institutes or has instituted against it, by a regulator, supervisor or any similar official with primary insolvency, rehabilitative or regulatory jurisdiction over it
in the jurisdiction of its incorporation or organization or the jurisdiction of its head or home office, a proceeding seeking a judgment of insolvency or bankruptcy or
any other relief under any bankruptcy or insolvency law or other similar law affecting creditors’ rights, or a petition is presented for its winding-up or liquidation by
it or such regulator, supervisor or similar official, or (B) has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief
under any bankruptcy or insolvency law or other similar law affecting creditors’ rights, or a petition is presented for its winding-up or liquidation, and such
proceeding or petition is instituted or presented by a person or entity not described in clause (A) above and either (I) results in a judgment of insolvency or
bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (II) is not dismissed, discharged, stayed or restrained in
each case within 15 days of the institution or presentation thereof; (5) has a resolution passed for its winding-up, official management or liquidation (other than
pursuant to a consolidation, amalgamation or merger); (6) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator,
receiver, trustee, custodian or other similar official for it or for all or substantially all its assets; (7) has a secured party take possession of all or substantially all its
assets or has a distress, execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all its assets and such
secured party maintains possession, or any such process is not dismissed, discharged, stayed or restrained, in each case within 15 days thereafter; (8) causes or is
subject to any event with respect to it which, under the applicable laws of any jurisdiction, has an analogous effect to any of the events specified in clauses (l) to
(7) above (inclusive); or (9) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts; or
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(viii) Merger Without Assumption. The party or any Credit Support Provider of such party consolidates or amalgamates with, or merges with or into, or transfers all
or substantially all its assets to, or reorganizes, reincorporates or reconstitutes into or as, another entity and, at the time of such consolidation, amalgamation, merger,
transfer, reorganisation, reincorporation or reconstitution:—
(l) the resulting, surviving or transferee entity fails to assume all the obligations of such party or such Credit Support Provider under this Agreement or any Credit
Support Document to which it or its predecessor was a party; or
(2) the benefits of any Credit Support Document fail to extend (without the consent of the other party) to the performance by such resulting, surviving or transferee
entity of its obligations under this Agreement.
(b) Termination Events. The occurrence at any time with respect to a party or, if applicable, any Credit Support Provider of such party or any Specified Entity of such
party of any event specified below constitutes (subject to Section 5(c)) an Illegality if the event is specified in clause (i) below, a Force Majeure Event if the event is
specified in clause (ii) below, a Tax Event if the event is specified in clause (iii) below, a Tax Event Upon Merger if the event is specified in clause (iv) below, and, if
specified to be applicable, a Credit Event Upon Merger if the event is specified pursuant to clause (v) below or an Additional Termination Event if the event is specified
pursuant to clause (vi) below:—
(i) Illegality. After giving effect to any applicable provision, disruption fallback or remedy specified in, or pursuant to, the relevant Confirmation or elsewhere in this
Agreement, due to an event or circumstance (other than any action taken by a party or, if applicable, any Credit Support Provider of such party) occurring after a
Transaction is entered into, it becomes unlawful under any applicable law (including without limitation the laws of any country in which payment, delivery or
compliance is required by either party or any Credit Support Provider, as the case may be), on any day, or it would be unlawful if the relevant payment, delivery or
compliance were required on that day (in each case, other than as a result of a breach by the party of Section 4(b)):—
(1) for the Office through which such party (which will be the Affected Party) makes and receives payments or deliveries with respect to such Transaction to perform
any absolute or contingent obligation to make a payment or delivery in respect of such Transaction, to receive a payment or delivery in respect of such Transaction or
to comply with any other material provision of this Agreement relating to such Transaction; or
(2) for such party or any Credit Support Provider of such party (which will be the Affected Party) to perform any absolute or contingent obligation to make a
payment or delivery which such party or Credit Support Provider has under any Credit Support Document relating to such Transaction, to receive a payment or
delivery under such Credit Support Document or to comply with any other material provision of such Credit Support Document;
(ii) Force Majeure Event. After giving effect to any applicable provision, disruption fallback or remedy specified in, or pursuant to, the relevant Confirmation or
elsewhere in this Agreement, by reason of force majeure or act of state occurring after a Transaction is entered into, on any day:—
(1) the Office through which such party (which will be the Affected Party) makes and receives payments or deliveries with respect to such Transaction is prevented
from performing any absolute or contingent obligation to make a payment or delivery in respect of such Transaction, from receiving a payment or delivery in respect
of such Transaction or from complying with any other material provision of this Agreement relating to such Transaction (or would be so prevented if such payment,
delivery or compliance were required on that day), or it becomes impossible or impracticable for such Office so to perform, receive
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or comply (or it would be impossible or impracticable for such Office so to perform, receive or comply if such payment, delivery or compliance were required on that
day); or
(2) such party or any Credit Support Provider of such party (which will be the Affected Party) is prevented from performing any absolute or contingent obligation to
make a payment or delivery which such party or Credit Support Provider has under any Credit Support Document relating to such Transaction, from receiving a
payment or delivery under such Credit Support Document or from complying with any other material provision of such Credit Support Document (or would be so
prevented if such payment, delivery or compliance were required on that day), or it becomes impossible or impracticable for such party or Credit Support Provider so
to perform, receive or comply (or it would be impossible or impracticable for such party or Credit Support Provider so to perform, receive or comply if such
payment, delivery or compliance were required on that day),
so long as the force majeure or act of state is beyond the control of such Office, such party or such Credit Support Provider, as appropriate, and such Office, party or
Credit Support Provider could not, after using all reasonable efforts (which will not require such party or Credit Support Provider to incur a loss, other than
immaterial, incidental expenses), overcome such prevention, impossibility or impracticability;
(iii) Tax Event. Due to (1) any action taken by a taxing authority, or brought in a court of competent jurisdiction, after a Transaction is entered into (regardless of
whether such action is taken or brought with respect to a party to this Agreement) or (2) a Change in Tax Law, the party (which will be the Affected Party) will, or
there is a substantial likelihood that it will, on the next succeeding Scheduled Settlement Date (A) be required to pay to the other party an additional amount in respect
of an Indemnifiable Tax under Section 2(d)(i)(4) (except in respect of interest under Section 9(h)) or (B) receive a payment from which an amount is required to be
deducted or withheld for or on account of a Tax (except in respect of interest under Section 9(h)) and no additional amount is required to be paid in respect of such Tax
under Section 2(d)(i)(4) (other than by reason of Section 2(d)(i)(4)(A) or (B));
(iv) Tax Event Upon Merger. The party (the “Burdened Party”) on the next succeeding Scheduled Settlement Date will either (1) be required to pay an additional
amount in respect of an Indemnifiable Tax under Section 2(d)(i)(4) (except in respect of interest under Section 9(h) or (2) receive a payment from which an amount
has been deducted or withheld for or on account of any Tax in respect of which the other party is not required to pay an additional amount (other than by reason of
Section 2(d)(i)(4)(A) or (B)), in either case as a result of a party consolidating or amalgamating with, or merging with or into, or transferring all or substantially all its
assets (or any substantial part of the assets comprising the business conducted by it as of the date of this Master Agreement) to, or reorganizing, reincorporating or
reconstituting into or as, another entity (which will be the Affected Party) where such action does not constitute a Merger Without Assumption;
(v) Credit Event Upon Merger. If “Credit Event Upon Merger” is specified in the Schedule as applying to the party, a Designated Event (as defined below) occurs
with respect to such party, any Credit Support Provider of such party or any applicable Specified Entity of such party (in each case, “X”) and such Designated Event
does not constitute a Merger Without Assumption, and the creditworthiness of X or, if applicable, the successor, surviving or transferee entity of X, after taking into
account any applicable Credit Support Document, is materially weaker immediately after the occurrence of such Designated Event than that of X immediately prior to
the occurrence of such Designated Event (and, in any such event, such party or its successor, surviving or transferee entity, as appropriate, will be the Affected Party).
A “Designated Event” with respect to X means that:—
(1) X consolidates or amalgamates with, or merges with or into, or transfers all or substantially all its assets (or any substantial part of the assets comprising the
business conducted by X as of the
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date of this Master Agreement) to, or reorganizes, reincorporates or reconstitutes into or as, another entity;
(2) any person, related group of persons or entity acquires directly or indirectly the beneficial ownership of (A) equity securities having the power to elect a majority
of the board of directors (or its equivalent) of X or (B) any other ownership interest enabling it to exercise control of X; or
(3) X effects any substantial change in its capital structure by means of the issuance, incurrence or guarantee of debt or the issuance of (A) preferred stock or other
securities convertible into or exchangeable for debt or preferred stock or (B) in the case of entities other than corporations, any other form of ownership interest; or
(vi) Additional Termination Event. If any “Additional Termination Event” is specified in the Schedule or any Confirmation as applying, the occurrence of such event
(and, in such event, the Affected Party or Affected Parties will be as specified for such Additional Termination Event in the Schedule or such Confirmation).
(c) Hierarchy of Events.
(i) An event or circumstance that constitutes or gives rise to an Illegality or a Force Majeure Event will not, for so long as that is the case, also constitute or give rise to
an Event of Default under Section 5(a)(i), 5(a)(ii)(1) or 5(a)(iii)(1) insofar as such event or circumstance relates to the failure to make any payment or delivery or a
failure to comply with any other material provision of this Agreement or a Credit Support Document, as the case may be.
(ii) Except in circumstances contemplated by clause (i) above, if an event or circumstance which would otherwise constitute or give rise to an Illegality or a Force
Majeure Event also constitutes an Event of Default or any other Termination Event, it will be treated as an Event of Default or such other Termination Event, as the
case may be, and will not constitute or give rise to an Illegality or a Force Majeure Event.
(iii) If an event or circumstance which would otherwise constitute or give rise to a Force Majeure Event also constitutes an Illegality, it will be treated as an Illegality,
except as described in clause (ii) above, and not a Force Majeure Event.
(d) Deferral of Payments and Deliveries During Waiting Period. If an Illegality or a Force Majeure Event has occurred and is continuing with respect to a Transaction,
each payment or delivery which would otherwise be required to be made under that Transaction will be deferred to, and will not be due until:—
(i) the first Local Business Day or, in the case of a delivery, the first Local Delivery Day (or the first day that would have been a Local Business Day or Local Delivery
Day, as appropriate, but for the occurrence of the event or circumstance constituting or giving rise to that Illegality or Force Majeure Event) following the end of any
applicable Waiting Period in respect of that Illegality or Force Majeure Event, as the case may be; or
(ii) if earlier, the date on which the event or circumstance constituting or giving rise to that Illegality or Force Majeure Event ceases to exist or, if such date is not a
Local Business Day or, in the case of a delivery, a Local Delivery Day, the first following day that is a Local Business Day or Local Delivery Day, as appropriate.
(e) Inability of Head or Home Office to Perform Obligations of Branch. If (i) an Illegality or a Force
Majeure Event occurs under Section 5(b)(i)(1) or 5(b)(ii)(1) and the relevant Office is not the Affected Party’s head or home office, (ii) Section 10(a) applies, (iii) the
other party seeks performance of the relevant obligation or compliance
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with the relevant provision by the Affected Party’s head or home office and (iv) the Affected Party’s head or home office fails so to perform or comply due to the
occurrence of an event or circumstance which would, if that head or home office were the Office through which the Affected Party makes and receives payments and
deliveries with respect to the relevant Transaction, constitute or give rise to an Illegality or a Force Majeure Event, and such failure would otherwise constitute an Event
of Default under Section 5(a)(i) or 5(a)(iii)(1) with respect to such party, then, for so long as the relevant event or circumstance continues to exist with respect to both
the Office referred to in Section 5(b)(i)(1) or 5(b)(ii)(1), as the case may be, and the Affected Party’s head or home office, such failure will not constitute an Event of
Default under Section 5(a)(i) or 5(a)(iii)(1).
6. Early Termination; Close-Out Netting
(a) Right to Terminate Following Event of Default. If at any time an Event of Default with respect to a party (the “Defaulting Party”) has occurred and is then
continuing, the other party (the “Non-defaulting Party”) may, by not more than 20 days notice to the Defaulting Party specifying the relevant Event of Default,
designate a day not earlier than the day such notice is effective as an Early Termination Date in respect of all outstanding Transactions. If, however, “Automatic Early
Termination” is specified in the Schedule as applying to a party, then an Early Termination Date in respect of all outstanding Transactions will occur immediately upon
the occurrence with respect to such party of an Event of Default specified in Section 5(a)(vii)(1), (3), (5), (6) or, to the extent analogous thereto, (8), and as of the time
immediately preceding the institution of the relevant proceeding or the presentation of the relevant petition upon the occurrence with respect to such party of an Event
of Default specified in Section 5(a)(vii)(4) or, to the extent analogous thereto, (8).
(b) Right to Terminate Following Termination Event.
(i) Notice. If a Termination Event other than a Force Majeure Event occurs, an Affected Party will, promptly upon becoming aware of it, notify the other party,
specifying the nature of that Termination Event and each Affected Transaction, and will also give the other party such other information about that Termination Event
as the other party may reasonably require. If a Force Majeure Event occurs, each party will, promptly upon becoming aware of it, use all reasonable efforts to notify
the other party, specifying the nature of that Force Majeure Event, and will also give the other party such other information about that Force Majeure Event as the
other party may reasonably require.
(ii) Transfer to Avoid Termination Event. If a Tax Event occurs and there is only one Affected Party, or if a Tax Event Upon Merger occurs and the Burdened Party
is the Affected Party, the Affected Party will, as a condition to its right to designate an Early Termination Date under Section 6(b)(iv), use all reasonable efforts (which
will not require such party to incur a loss, other than immaterial, incidental expenses) to transfer within 20 days after it gives notice under Section 6(b)(i) all its rights
and obligations under this Agreement in respect of the Affected Transactions to another of its Offices or Affiliates so that such Termination Event ceases to exist.
If the Affected Party is not able to make such a transfer it will give notice to the other party to that effect within such 20 day period, whereupon the other party may
effect such a transfer within 30 days after the notice is given under Section 6(b)(i).
Any such transfer by a party under this Section 6(b)(ii) will be subject to and conditional upon the prior written consent of the other party, which consent will not be
withheld if such other party’s policies in effect at such time would permit it to enter into transactions with the transferee on the terms proposed.
(iii) Two Affected Parties. If a Tax Event occurs and there are two Affected Parties, each party will use all reasonable efforts to reach agreement within 30 days after
notice of such occurrence is given under Section 6(b)(i)to avoid that Termination Event.
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(iv) Right to Terminate.
(1) If:—
(A) a transfer under Section 6(b)(ii) or an agreement under Section 6(b)(iii), as the case may be, has not been effected with respect to all Affected Transactions
within 30 days after an Affected Party gives notice under Section 6(b)(i); or
(B) a Credit Event Upon Merger or an Additional Termination Event occurs, or a Tax Event Upon Merger occurs and the Burdened Party is not the Affected Party,
the Burdened Party in the case of a Tax Event Upon Merger, any Affected Party in the case of a Tax Event or an Additional Termination Event if there are two
Affected Parties, or the Non-affected Party in the case of a Credit Event Upon Merger or an Additional Termination Event if there is only one Affected Party may, if
the relevant Termination Event is then continuing, by not more than 20 days notice to the other party, designate a day not earlier than the day such notice is effective
as an Early Termination Date in respect of all Affected Transactions.
(2) If at any time an Illegality or a Force Majeure Event has occurred and is then continuing and any applicable Waiting Period has expired:—
(A) Subject to clause (B) below, either party may, by not more than 20 days notice to the other party, designate (I) a day not earlier than the day on which such
notice becomes effective as an Early Termination Date in respect of all Affected Transactions or (II) by specifying in that notice the Affected Transactions in
respect of which it is designating the relevant day as an Early Termination Date, a day not earlier than two Local Business Days following the day on which such
notice becomes effective as an Early Termination Date in respect of less than all Affected Transactions. Upon receipt of a notice designating an Early Termination
Date in respect of less than all Affected Transactions, the other party may, by notice to the designating party, if such notice is effective on or before the day so
designated, designate that same day as an Early Termination Date in respect of any or all other Affected Transactions.
(B) An Affected Party (if the Illegality or Force Majeure Event relates to performance by such party or any Credit Support Provider of such party of an obligation
to make any payment or delivery under, or to compliance with any other material provision of, the relevant Credit Support Document) will only have the right to
designate an Early Termination Date under Section 6(b)(iv)(2)(A) as a result of an Illegality under Section 5(b)(i)(2) or a Force Majeure Event under
Section 5(b)(ii)(2) following the prior designation by the other party of an Early Termination Date, pursuant to Section 6(b)(iv)(2)(A), in respect of less than all
Affected Transactions.
(c) Effect of Designation.
(i) If notice designating an Early Termination Date is given under Section 6(a) or 6(b), the Early Termination Date will occur on the date so designated, whether or not
the relevant Event of Default or Termination Event is then continuing.
(ii) Upon the occurrence or effective designation of an Early Termination Date, no further payments or deliveries under Section 2(a)(i) or 9(h)(i) in respect of the
Terminated Transactions will be required to be made, but without prejudice to the other provisions of this Agreement. The amount, if any, payable in respect of an
Early Termination Date will be determined pursuant to Sections 6(e) and 9(h)(ii).
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(d) Calculations; Payment Date.
(i) Statement. On or as soon as reasonably practicable following the occurrence of an Early Termination Date, each party will make the calculations on its part, if any,
contemplated by Section 6(e) and will provide to the other party a statement (l) showing, in reasonable detail, such calculations (including any quotations, market data
or information from internal sources used in making such calculations), (2) specifying (except where there are two Affected Parties) any Early Termination Amount
payable and (3) giving details of the relevant account to which any amount payable to it is to be paid. In the absence of written confirmation from the source of a
quotation or market data obtained in determining a Close-out Amount, the records of the party obtaining such quotation or market data will be conclusive evidence of
the existence and accuracy of such quotation or market data.
(ii) Payment Date. An Early Termination Amount due in respect of any Early Termination Date will, together with any amount of interest payable pursuant to
Section 9(h)(ii)(2), be payable (1) on the day on which notice of the amount payable is effective in the case of an Early Termination Date which is designated or
occurs as a result of an Event of Default and (2) on the day which is two Local Business Days after the day on which notice of the amount payable is effective (or, if
there are two Affected Parties, after the day on which the statement provided pursuant to clause (i) above by the second party to provide such a statement is effective)
in the case of an Early Termination Date which is designated as a result of a Termination Event.
(e) Payments on Early Termination. If an Early Termination Date occurs, the amount, if any, payable in respect of that Early Termination Date (the “Early
Termination Amount”) will be determined pursuant to this Section 6(e) and will be subject to Section 6(f).
(i) Events of Default. If the Early Termination Date results from an Event of Default, the Early Termination Amount will be an amount equal to (1) the sum of (A) the
Termination Currency Equivalent of the Close-out Amount or Close-out Amounts (whether positive or negative) determined by the Non-defaulting Party for each
Terminated Transaction or group of Terminated Transactions, as the case may be, and (B) the Termination Currency Equivalent of the Unpaid Amounts owing to the
Non-defaulting Party less (2) the Termination Currency Equivalent of the Unpaid Amounts owing to the Defaulting Party. If the Early Termination Amount is a
positive number, the Defaulting Party will pay it to the Non-defaulting Party; if it is a negative number, the Non-defaulting Party will pay the absolute value of Early
Termination Amount to the Defaulting Party.
(ii) Termination Events. If the Early Termination Date results from a Termination Event:—
(1) One Affected Party. Subject to clause (3) below, if there is one Affected Party, the Early Termination Amount will be determined in accordance with
Section 6(e)(i), except that references to the Defaulting Party and to the Non-defaulting Party will be deemed to be references to the Affected Party and to the
Non-affected Party, respectively.
(2) Two Affected Parties. Subject to clause (3) below, if there are two Affected Parties, each party will determine an amount equal to the Termination Currency
Equivalent of the sum of the Close-out Amount or Close-out Amounts (whether positive or negative) for each Terminated Transaction or group of Terminated
Transactions, as the case may be, and the Early Termination Amount will be an amount equal to (A) the sum of (I) one-half of the difference between the higher
amount so determined (by party “X”) and lower amount so determined (by party “Y”) and (II) the Termination Currency Equivalent of the Unpaid Amounts owing to
X less (B) the Termination Currency Equivalent of the Unpaid Amounts owing to Y. If the Early Termination Amount is a positive number, Y will pay it to X; if it is
a negative number, X will pay the absolute value of the Early Termination Amount to Y.
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(3) Mid-Market Events. If that Termination Event is an Illegality or a Force Majeure Event, then the Early Termination Amount will be determined in accordance
with clause (1) or (2) above, as appropriate, except that, for the purpose of determining a Close-out Amount or Close-out Amounts, the Determining Party will:—
(A) if obtaining quotations from one or more third parties (or from any of the Determining Party’s Affiliates), ask each third party or Affiliate (I) not to take
account of the current creditworthiness of the Determining Party or any existing Credit Support Document and (II) to provide mid-market quotations; and
(B) in any other case, use mid-market values without regard to the creditworthiness of the Determining Party.
(iii) Adjustment for Bankruptcy. In circumstances where an Early Termination Date occurs because Automatic Early Termination applies in respect of a party, Early
Termination Amount will be subject to such adjustments as are appropriate and permitted by applicable law to reflect any payments or deliveries made by one party to
the other under this Agreement (and retained by such other party) during the period from the relevant Early Termination Date to the date for payment determined
under Section 6(d)(ii).
(iv) Adjustment for Illegality or Force Majeure Event. The failure by a party or any Credit Support Provider of such party to pay, when due, any Early Termination
Amount will not constitute an Event of Default under Section 5(a)(i) or 5(a)(iii)(1) if such failure is due to the occurrence of an event or circumstance which would, if
it occurred with respect to payment, delivery or compliance related to a Transaction, constitute or give rise to an Illegality or a Force Majeure Event. Such amount will
(1) accrue interest and otherwise be treated as an Unpaid Amount owing to the other party if subsequently an Early Termination Date results from an Event of Default,
a Credit Event Upon Merger or an Additional Termination Event in respect of which all outstanding Transactions are Affected Transactions and (2) otherwise accrue
interest in accordance with Section 9(h)(ii)(2).
(v) Pre-Estimate. The parties agree that an amount recoverable under this Section 6(e) is a reasonable pre-estimate of loss and not a penalty. Such amount is payable
for the loss of bargain and the loss of protection against future risks, and, except as otherwise provided in this Agreement, neither party will be entitled to recover any
additional damages as a consequence of the termination of the Terminated Transactions.
(f) Set-Off. Any Early Termination Amount payable to one party (the “Payee”) by the other party (the “Payer”), in circumstances where there is a Defaulting Party or
where there is one Affected Party in the case where either a Credit Event Upon Merger has occurred or any other Termination Event in respect of which all outstanding
Transactions are Affected Transactions has occurred, will, at the option of the Non-defaulting Party or the Non-affected Party, as the case may be (“X”) (and without
prior notice to the Defaulting Party or the Affected Party, as the case may be), be reduced by its set-off against any other amounts (“Other Amounts”) payable by the
Payee to the Payer (whether or not arising under this Agreement, matured or contingent and irrespective of the currency, place of payment or place of booking of the
obligation). To the extent that any Other Amounts are so set off, those Other Amounts will be discharged promptly and in all respects. X will give notice to the other
party of any set-off effected under this Section 6(f).
For this purpose, either the Early Termination Amount or the Other Amounts (or the relevant portion of such amounts) may be converted by X into the currency in
which the other is denominated at the rate of exchange at which such party would be able, in good faith and using commercially reasonable procedures, to purchase the
relevant amount of such currency.
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If an obligation is unascertained, X may in good faith estimate that obligation and set off in respect of the estimate, subject to the relevant party accounting to the other
when the obligation is ascertained.
Nothing in this Section 6(f) will be effective to create a charge or other security interest. This Section 6(f) will be without prejudice and in addition to any right of
set-off, offset, combination of accounts, lien, right of retention or withholding or similar right or requirement to which any party is at any time otherwise entitled or
subject (whether by operation of law, contract or otherwise).
7. Transfer
Subject to Section 6(b)(ii) and to the extent permitted by applicable law, neither this Agreement nor any interest or obligation in or under this Agreement may be
transferred (whether by way of security or otherwise) by either party without the prior written consent of the other party, except that:—
(a) a party may make such a transfer of this Agreement pursuant to a consolidation or amalgamation with, or merger with or into, or transfer of all or substantially all its
assets to, another entity (but without prejudice to any other right or remedy under this Agreement); and
(b) a party may make such a transfer of all or any part of its interest in any Early Termination Amount payable to it by a Defaulting Party, together with any amounts
payable on or with respect to that interest and any other rights associated with that interest pursuant to Sections 8, 9(h) and 11.
Any purported transfer that is not in compliance with this Section 7 will be void.
8. Contractual Currency
(a) Payment in the Contractual Currency. Each payment under this Agreement will be made in the relevant currency specified in this Agreement for that payment (the
“Contractual Currency”). To the extent permitted by applicable law, any obligation to make payments under this Agreement in the Contractual Currency will not be
discharged or satisfied by any tender in any currency other than the Contractual Currency, except to the extent such tender results in the actual receipt by the party to
which payment is owed, acting in good faith and using commercially reasonable procedures in converting the currency so tendered into the Contractual Currency, of the
full amount in the Contractual Currency of all amounts payable in respect of this Agreement. If for any reason the amount in the Contractual Currency so received falls
short of the amount in the Contractual Currency payable in respect of this Agreement, the party required to make the payment will, to the extent permitted by applicable
law, immediately pay such additional amount in the Contractual Currency as may be necessary to compensate for the shortfall. If for any reason the amount in the
Contractual Currency so received exceeds the amount in the Contractual Currency payable in respect of this Agreement, the party receiving the payment will refund
promptly the amount of such excess.
(b) Judgments. To the extent permitted by applicable law, if any judgment or order expressed in a currency other than the Contractual Currency is rendered (i) for the
payment of any amount owing in respect of this Agreement, (ii) for the payment of any amount relating to any early termination in respect of this Agreement or (iii) in
respect of a judgment or order of another court for the payment of any amount described in clause (i) or (ii) above, the party seeking recovery, after recovery in full of
the aggregate amount to which such party is entitled pursuant to the judgment or order, will be entitled to receive immediately from the other party the amount of any
shortfall of the Contractual Currency received by such party as a consequence of sums paid in such other currency and will refund promptly to the other party any
excess of the Contractual Currency received by such party as a consequence of sums paid in such other currency if such shortfall or such excess arises or results from
any variation between the rate of exchange at which the Contractual Currency is converted into the currency of the judgment or order for the purpose of such judgment
or order and the rate of exchange at which such party is able, acting in good faith and using
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commercially reasonable procedures in converting the currency received into the Contractual Currency, to purchase the Contractual Currency with the amount of the
currency of the judgment or order actually received by such party.
(c) Separate Indemnities. To the extent permitted by applicable law, the indemnities in this Section 8 constitute separate and independent obligations from the other
obligations in this Agreement, will be enforceable as separate and independent causes of action, will apply notwithstanding any indulgence granted by the party to
which any payment is owed and will not be affected by judgment being obtained or claim or proof being made for any other sums payable in respect of this Agreement.
(d) Evidence of Loss. For the purpose of this Section 8, it will be sufficient for a party to demonstrate that it would have suffered a loss had an actual exchange or
purchase been made.
9. Miscellaneous
(a) Entire Agreement. This Agreement constitutes the entire agreement and understanding of the parties with respect to its subject matter. Each of the parties
acknowledges that in entering into this Agreement it has not relied on any oral or written representation, warranty or other assurance (except as provided for or referred
to in this Agreement) and waives all rights and remedies which might otherwise be available to it in respect thereof, except that nothing in this Agreement will limit or
exclude any liability of a party for fraud.
(b) Amendments. An amendment, modification or waiver in respect of this Agreement will only be effective if in writing (including a writing evidenced by a facsimile
transmission) and executed by each of the parties or confirmed by an exchange of telexes or by an exchange of electronic messages on an electronic messaging system.
(c) Survival of Obligations. Without prejudice to Sections 2(a)(iii) and 6(c)(ii), the obligations of the parties under this Agreement will survive the termination of any
Transaction.
(d) Remedies Cumulative. Except as provided in this Agreement, the rights, powers, remedies and privileges provided in this Agreement are cumulative and not
exclusive of any rights, powers, remedies and privileges provided by law.
(e)
Counterparts and Confirmations.
(i) This Agreement (and each amendment, modification and waiver in respect of it) may be executed and delivered in counterparts (including by facsimile
transmission and by electronic messaging system), each of which will be deemed an original.
(ii) The parties intend that they are legally bound by the terms of each Transaction from the moment they agree to those terms (whether orally or otherwise). A
Confirmation will be entered into as soon as practicable and may be executed and delivered in counterparts (including by facsimile transmission) or be created by an
exchange of telexes, by an exchange of electronic messages on an electronic messaging system or by an exchange of e-mails, which in each case will be sufficient for
all purposes to evidence a binding supplement to this Agreement. The parties will specify therein or through another effective means that any such counterpart, telex,
electronic message or e-mail constitutes a Confirmation.
(f) No Waiver of Rights. A failure or delay in exercising any right, power or privilege in respect of this Agreement will not be presumed to operate as a waiver, and a
single or partial exercise of any right, power or privilege will not be presumed to preclude any subsequent or further exercise, of that right, power or privilege or the
exercise of any other right, power or privilege.
(g) Headings. The headings used in this Agreement are for convenience of reference only and are not to affect the construction of or to be taken into consideration in
interpreting this Agreement.
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(h) Interest and Compensation.
(i) Prior to Early Termination. Prior to the occurrence or effective designation of an Early Termination Date in respect of the relevant Transaction:—
(1) Interest on Defaulted Payments. If a party defaults in the performance of any payment obligation, it will, to the extent permitted by applicable law and subject to
Section 6(c), pay interest (before as well as after judgment) on the overdue amount to the other party on demand in the same currency as the overdue amount, for the
period from (and including) the original due date for payment to (but excluding) the date of actual payment (and excluding any period in respect of which interest or
compensation in respect of the overdue amount is due pursuant to clause (3)(B) or (C) below), at the Default Rate.
(2) Compensation for Defaulted Deliveries. If a party defaults in the performance of any obligation required to be settled by delivery, it will on demand
(A) compensate the other party to the extent provided for in the relevant Confirmation or elsewhere in this Agreement and (B) unless otherwise provided in the
relevant Confirmation or elsewhere in this Agreement, to the extent permitted by applicable law and subject to Section 6(c), pay to the other party interest (before as
well as after judgment) on an amount equal to the fair market value of that which was required to be delivered in the same currency as that amount, for the period
from (and including) the originally scheduled date for delivery to (but excluding) the date of actual delivery (and excluding any period in respect of which interest or
compensation in respect of that amount is due pursuant to clause (4) below), at the Default Rate. The fair market value of any obligation referred to above will be
determined as of the originally scheduled date for delivery, in good faith and using commercially reasonable procedures, by the party that was entitled to take
delivery.
(3) Interest on Deferred Payments. If:—
(A) a party does not pay any amount that, but for Section 2(a)(iii), would have been payable, it will, to the extent permitted by applicable law and subject to
Section 6(c) and clauses (B) and (C) below, pay interest (before as well as after judgment) on that amount to the other party on demand (after such amount becomes
payable) in the same currency as that amount, for the period from (and including) the date the amount would, but for Section 2(a)(iii), have been payable to (but
excluding) the date the amount actually becomes payable, at the Applicable Deferral Rate;
(B) a payment is deferred pursuant to Section 5(d), the party which would otherwise have been required to make that payment will, to the extent permitted by
applicable law, subject to Section 6(c) and for so long as no Event of Default or Potential Event of Default with respect to that party has occurred and is continuing,
pay interest (before as well as after judgment) on the amount of the deferred payment to the other party on demand (after such amount becomes payable) in the
same currency as the deferred payment, for the period from (and including) the date the amount would, but for Section 5(d), have been payable to (but excluding)
the earlier of the date the payment is no longer deferred pursuant to Section 5(d) and the date during the deferral period upon which an Event of Default or Potential
Event of Default with respect to that party occurs, at the Applicable Deferral Rate; or
(C) a party fails to make any payment due to the occurrence of an Illegality or a Force
Majeure Event (after giving effect to any deferral period contemplated by clause (B) above), it will, to the extent permitted by applicable law, subject to
Section 6(c) and for so long as the event or circumstance giving rise to that Illegality or Force Majeure Event continues and
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no Event of Default or Potential Event of Default with respect to that party has occurred and is continuing, pay interest (before as well as after judgment) on the
overdue amount to the other party on demand in the same currency as the overdue amount, for the period from (and including) the date the party fails to make the
payment due to the occurrence of the relevant Illegality or Force Majeure Event (or, if later, the date the payment is no longer deferred pursuant to Section 5(d)) to
(but excluding) the earlier of the date the event or circumstance giving rise to that Illegality or Force Majeure Event ceases to exist and the date during the period
upon which an Event of Default or Potential Event of Default with respect to that party occurs (and excluding any period in respect of which interest or
compensation in respect of the overdue amount is due pursuant to clause (B) above), at the Applicable Deferral Rate.
(4) Compensation for Deferred Deliveries. If:—
(A) a party does not perform any obligation that, but for Section 2(a)(iii), would have been required to be settled by delivery;
(B) a delivery is deferred pursuant to Section 5(d); or
(C) a party fails to make a delivery due to the occurrence of an Illegality or a Force Majeure Event at a time when any applicable Waiting Period has expired,
the party required (or that would otherwise have been required) to make the delivery will, to the extent permitted by applicable law and subject to Section 6(c),
compensate and pay interest to the other party on demand (after, in the case of clauses (A) and (B) above, such delivery is required) if and to the extent provided for in
the relevant Confirmation or elsewhere in this Agreement.
(ii) Early Termination. Upon the occurrence or effective designation of an Early Termination Date in respect of a Transaction:—
(1) Unpaid Amounts. For the purpose of determining an Unpaid Amount in respect of the relevant Transaction, and to the extent permitted by applicable law, interest
will accrue on the amount of any payment obligation or the amount equal to the fair market value of any obligation required to be settled by delivery included in such
determination in the same currency as that amount, for the period from (and including) the date the relevant obligation was (or would have been but for
Section 2(a)(iii) or 5(d)) required to have been performed to (but excluding) the relevant Early Termination Date, at the Applicable Close-out Rate.
(2) Interest on Early Termination Amounts. If an Early Termination Amount is due in respect of such Early Termination Date, that amount will, to the extent
permitted by applicable law, be paid together with interest (before as well as after judgment) on that amount in the Termination Currency, for the period from (and
including) such Early Termination Date to (but excluding) the date the amount is paid, at the Applicable Close-out Rate.
(iii) Interest Calculation. Any interest pursuant to this Section 9(h) will be calculated on the basis of daily compounding and the actual number of days elapsed.
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10. Offices; Multibranch Parties
(a) If Section 10(a) is specified in the Schedule as applying, each party that enters into a Transaction through an Office other than its head or home office represents to
and agrees with the other party that, notwithstanding the place of booking or its jurisdiction of incorporation or organization, its obligations are the same in terms of
recourse against it as if it had entered into the Transaction through its head or home office, except that a party will not have recourse to the head or home office of the
other party in respect of any payment or delivery deferred pursuant to Section 5(d) for so long as the payment or delivery is so deferred. This representation and
agreement will be deemed to be repeated by each party on each date on which the parties enter into a Transaction.
(b) If a party is specified as a Multibranch Party in the Schedule, such party may, subject to clause (c) below, enter into a Transaction through, book a Transaction in
and make and receive payments and deliveries with respect to a Transaction through any Office listed in respect of that party in the Schedule (but not any other Office
unless otherwise agreed by the parties in writing).
(c) The Office through which a party enters into a Transaction will be the Office specified for that party in the relevant Confirmation or as otherwise agreed by the
parties in writing, and, if an Office for that party is not specified in the Confirmation or otherwise agreed by the parties in writing, its head or home office. Unless the
parties otherwise agree in writing, the Office through which a party enters into a Transaction will also be the Office in which it books the Transaction and the Office
through which it makes and receives payments and deliveries with respect to the Transaction. Subject to Section 6(b)(ii), neither party may change the Office in which it
books the Transaction or the Office through which it makes and receives payments or deliveries with respect to a Transaction without the prior written consent of the
other party.
11. Expenses
A Defaulting Party will on demand indemnify and hold harmless the other party for and against all reasonable out-of-pocket expenses, including legal fees, execution
fees and Stamp Tax, incurred by such other party by reason of the enforcement and protection of its rights under this Agreement or any Credit Support Document to
which the Defaulting Party is a party or by reason of the early termination of any Transaction, including, but not limited to, costs of collection.
12. Notices
(a) Effectiveness. Any notice or other communication in respect of this Agreement may be given in any manner described below (except that a notice or other
communication under Section 5 or 6 may not be given by electronic messaging system or e-mail) to the address or number or in accordance with the electronic
messaging system or e-mail details provided (see the Schedule) and will be deemed effective as indicated:—
(i) if in writing and delivered in person or by courier, on the date it is delivered;
(ii) if sent by telex, on the date the recipient’s answerback is received;
(iii) if sent by facsimile transmission, on the date it is received by a responsible employee of the recipient in legible form (it being agreed that the burden of proving
receipt will be on the sender and will not be met by a transmission report generated by the sender’s facsimile machine);
(iv) if sent by certified or registered mail (airmail, if overseas) or the equivalent (return receipt requested), on the date it is delivered or its delivery is attempted;
(v) if sent by electronic messaging system, on the date it is received; or
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(vi) if sent by e-mail, on the date it is delivered,
unless the date of that delivery (or attempted delivery) or that receipt, as applicable, is not a Local Business Day or that communication is delivered (or attempted) or
received, as applicable, after the close of business on a Local Business Day, in which case that communication will be deemed given and effective on the first following
day that is a Local Business Day.
(b) Change of Details. Either party may by notice to the other change the address, telex or facsimile number or electronic messaging system or e-mail details at which
notices or other communications are to be given to it.
13. Governing Law and Jurisdiction
(a) Governing Law. This Agreement will be governed by and construed in accordance with the law specified in the Schedule.
(b) Jurisdiction. With respect to any suit, action or proceedings relating to any dispute arising out of or in connection with this Agreement (“Proceedings”), each party
irrevocably:—
(i) submits:—
(1) if this Agreement is expressed to be governed by English law, to (A) the non-exclusive jurisdiction of the English courts if the Proceedings do not involve a
Convention Court and (B) the exclusive jurisdiction of the English courts if the Proceedings do involve a Convention Court; or
(2) if this Agreement is expressed to be governed by the laws of the State of New York, to the non-exclusive jurisdiction of the courts of the State of New York and
the United States District Court located in the Borough of Manhattan in New York City;
(ii) waives any objection which it may have at any time to the laying of venue of any Proceedings brought in any such court, waives any claim that such Proceedings
have been brought in an inconvenient forum and further waives the right to object, with respect to such Proceedings, that such court does not have any jurisdiction
over such party; and
(iii) agrees, to the extent permitted by applicable law, that the bringing of Proceedings in any one or more jurisdictions will not preclude the bringing of Proceedings in
any other jurisdiction.
(c) Service of Process. Each party irrevocably appoints the Process Agent, if any, specified opposite its name in the Schedule to receive, for it and on its behalf, service
of process in any Proceedings. If for any reason any party’s Process Agent is unable to act as such, such party will promptly notify the other party and within 30 days
appoint a substitute process agent acceptable to the other party. The parties irrevocably consent to service of process given in the manner provided for notices in
Section 12(a)(i), 12(a)(iii) or 12(a)(iv). Nothing in this Agreement will affect the right of either party to serve process in any other manner permitted by applicable law.
(d) Waiver of Immunities. Each party irrevocably waives, to the extent permitted by applicable law, with respect to itself and its revenues and assets (irrespective of
their use or intended use), all immunity on the grounds of sovereignty or other similar grounds from (i) suit, (ii) jurisdiction of any court, (iii) relief by way of injunction
or order for specific performance or recovery of property, (iv) attachment of its assets (whether before or after judgment) and (v) execution or enforcement of any
judgment to which it or its revenues or assets might otherwise be entitled in any Proceedings in the courts of any jurisdiction and irrevocably agrees, to the extent
permitted by applicable law, that it will not claim any such immunity in any Proceedings.
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14. Definitions
As used in this Agreement:—
“Additional Representation” has the meaning specified in Section 3.
“Additional Termination Event” has the meaning specified in Section 5(b).
“Affected Party” has the meaning specified in Section 5(b).
“Affected Transactions” means (a) with respect to any Termination Event consisting of an Illegality, Force Majeure Event, Tax Event or Tax Event Upon Merger, all
Transactions affected by the occurrence of such Termination Event (which, in the case of an Illegality under Section 5(b)(i)(2) or a Force Majeure Event under
Section 5(b)(ii)(2), means all Transactions unless the relevant Credit Support Document references only certain Transactions, in which case those Transactions and, if
the relevant Credit Support Document constitutes a Confirmation for a Transaction, that Transaction) and (b) with respect to any other Termination Event, all
Transactions.
“Affiliate” means, subject to the Schedule, in relation to any person, any entity controlled, directly or indirectly, by the person, any entity that controls, directly or
indirectly, the person or any entity directly or indirectly under common control with the person. For this purpose, “control” of any entity or person means ownership of
a majority of the voting power of the entity or person.
“Agreement” has the meaning specified in Section 1(c).
“Applicable Close-out Rate” means:—
(a) in respect of the determination of an Unpaid Amount:—
(i) in respect of obligations payable or deliverable (or which would have been but for Section 2(a)(iii)) by a Defaulting Party, the Default Rate;
(ii) in respect of obligations payable or deliverable (or which would have been but for Section 2(a)(iii)) by a Non-defaulting Party, the Non-default Rate;
(iii) in respect of obligations deferred pursuant to Section 5(d), if there is no Defaulting Party and for so long as the deferral period continues, the Applicable Deferral
Rate; and
(iv) in all other cases following the occurrence of a Termination Event (except where interest accrues pursuant to clause (iii) above), the Applicable Deferral Rate; and
(b) in respect of an Early Termination Amount:—
(i) for the period from (and including) the relevant Early Termination Date to (but excluding) the date (determined in accordance with Section 6(d)(ii)) on which that
amount is payable:—
(1) if the Early Termination Amount is payable by a Defaulting Party, the Default Rate;
(2) if the Early Termination Amount is payable by a Non-defaulting Party, the Non-default Rate; and
(3) in all other cases, the Applicable Deferral Rate; and
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(ii) for the period from (and including) the date (determined in accordance with Section 6(d)(ii)) on which that amount is payable to (but excluding) the date of actual
payment:—
(1) if a party fails to pay the Early Termination Amount due to the occurrence of an event or circumstance which would, if it occurred with respect to a payment or
delivery under a Transaction, constitute or give rise to an Illegality or a Force Majeure Event, and for so long as the Early Termination Amount remains unpaid due
to the continuing existence of such event or circumstance, the Applicable Deferral Rate;
(2) if the Early Termination Amount is payable by a Defaulting Party (but excluding any period in respect of which clause (1) above applies), the Default Rate;
(3) if the Early Termination Amount is payable by a Non-defaulting Party (but excluding any period in respect of which clause (1) above applies), the Non-default
Rate; and
(4) in all other cases, the Termination Rate.
“Applicable Deferral Rate” means:—
(a) for the purpose of Section 9(h)(i)(3)(A), the rate certified by the relevant payer to be a rate offered to the payer by a major bank in a relevant interbank market for
overnight deposits in the applicable currency, such bank to be selected in good faith by the payer for the purpose of obtaining a representative rate that will reasonably
reflect conditions prevailing at the time in that relevant market;
(b) for purposes of Section 9(h)(i)(3)(B) and clause (a)(iii) of the definition of Applicable Close-out Rate, the rate certified by the relevant payer to be a rate offered to
prime banks by a major bank in a relevant interbank market for overnight deposits in the applicable currency, such bank to be selected in good faith by the payer after
consultation with the other party, if practicable, for the purpose of obtaining a representative rate that will reasonably reflect conditions prevailing at the time in that
relevant market; and
(c) for purposes of Section 9(h)(i)(3)(C) and clauses (a)(iv), (b)(i)(3) and (b)(ii)(1) of the definition of Applicable Close-out Rate, a rate equal to the arithmetic mean of
the rate determined pursuant to clause (a) above and a rate per annum equal to the cost (without proof or evidence of any actual cost) to the relevant payee (as certified
by it) if it were to fund or of funding the relevant amount.
“Automatic Early Termination” has the meaning specified in Section 6(a).
“Burdened Party” has the meaning specified in Section 5(b)(iv).
“Change in Tax Law” means the enactment, promulgation, execution or ratification of, or any change in or amendment to, any law (or in the application or official
interpretation of any law) that occurs after the parties enter into the relevant Transaction.
“Close-out Amount” means, with respect to each Terminated Transaction or each group of Terminated Transactions and a Determining Party, the amount of the losses
or costs of the Determining Party that are or would be incurred under then prevailing circumstances (expressed as a positive number) or gains of the Determining Party
that are or would be realized under then prevailing circumstances (expressed as a negative number) in replacing, or in providing for the Determining Party the economic
equivalent of, (a) the material terms of that Terminated Transaction or group of Terminated Transactions, including the payments and deliveries by the parties under
Section 2(a)(i) in respect of that Terminated Transaction or group of Terminated Transactions that would, but for the occurrence of the relevant Early Termination Date,
have been required after that date (assuming satisfaction of the conditions precedent in
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Section 2(a)(iii)) and (b) the option rights of the parties in respect of that Terminated Transaction or group of Terminated Transactions.
Any Close-out Amount will be determined by the Determining Party (or its agent), which will act in good faith and use commercially reasonable procedures in order to
produce a commercially reasonable result. The Determining Party may determine a Close-out Amount for any group of Terminated Transactions or any individual
Terminated Transaction but, in the aggregate, for not less than all Terminated Transactions. Each Close-out Amount will be determined as of the Early Termination
Date or, if that would not be commercially reasonable, as of the date or dates following the Early Termination Date as would be commercially reasonable.
Unpaid Amounts in respect of a Terminated Transaction or group of Terminated Transactions and legal fees and out-of-pocket expenses referred to in Section 11 are to
be excluded in all determinations of Close-out Amounts.
In determining a Close-out Amount, the Determining Party may consider any relevant information, including, without limitation, one or more of the following types of
information:—
(i) quotations (either firm or indicative) for replacement transactions supplied by one or more third parties that may take into account the creditworthiness of the
Determining Party at the time the quotation is provided and the terms of any relevant documentation, including credit support documentation, between the Determining
Party and the third party providing the quotation;
(ii) information consisting of relevant market data in the relevant market supplied by one or more third parties including, without limitation, relevant rates, prices,
yields, yield curves, volatilities, spreads, correlations or other relevant market data in the relevant market; or
(iii) information of the types described in clause (i) or (ii) above from internal sources (including any of the Determining Party’s Affiliates) if that information is of the
same type used by the Determining Party in the regular course of its business for the valuation of similar transactions.
The Determining Party will consider, taking into account the standards and procedures described in this definition, quotations pursuant to clause (i) above or relevant
market data pursuant to clause (ii) above unless the Determining Party reasonably believes in good faith that such quotations or relevant market data are not readily
available or would produce a result that would not satisfy those standards. When considering information described in clause (i), (ii) or (iii) above, the Determining
Party may include costs of funding, to the extent costs of funding are not and would not be a component of the other information being utilized. Third parties supplying
quotations pursuant to clause (i) above or market data pursuant to clause (ii) above may include, without limitation, dealers in the relevant markets, end-users of the
relevant product, information vendors, brokers and other sources of market information.
Without duplication of amounts calculated based on information described in clause (i), (ii) or (iii) above, or other relevant information, and when it is commercially
reasonable to do so, the Determining Party may in addition consider in calculating a Close-out Amount any loss or cost incurred in connection with its terminating,
liquidating or re-establishing any hedge related to a Terminated Transaction or group of Terminated Transactions (or any gain resulting from any of them).
Commercially reasonable procedures used in determining a Close-out Amount may include the following:—
(1) application to relevant market data from third parties pursuant to clause (ii) above or information from internal sources pursuant to clause (iii) above of pricing or
other valuation models that are, at the time of the determination of the Close-out Amount, used by the Determining Party in the regular course of its business in pricing
or valuing transactions between the Determining Party and unrelated third parties that are similar to the Terminated Transaction or group of Terminated Transactions;
and
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(2) application of different valuation methods to Terminated Transactions or groups of Terminated Transactions depending on the type, complexity, size or number of
the Terminated Transactions or group of Terminated Transactions.
“Confirmation” has the meaning specified in the preamble.
“consent” includes a consent, approval, action, authorization, exemption, notice, filing, registration or exchange control consent.
“Contractual Currency” has the meaning specified in Section 8(a).
“Convention Court” means any court which is bound to apply to the Proceedings either Article 17 of the 1968 Brussels Convention on Jurisdiction and the
Enforcement of Judgments in Civil and Commercial Matters or Article 17 of the 1988 Lugano Convention on Jurisdiction and the Enforcement of Judgments in Civil
and Commercial Matters.
“Credit Event Upon Merger” has the meaning specified in Section 5(b).
“Credit Support Document” means any agreement or instrument that is specified as such in this Agreement.
“Credit Support Provider” has the meaning specified in the Schedule.
“Cross-Default” means the event specified in Section 5(a)(vi).
“Default Rate” means a rate per annum equal to the cost (without proof or evidence of any actual cost) to the relevant payee (as certified by it) if it were to fund or of
funding the relevant amount plus 1% per annum.
“Defaulting Party” has the meaning specified in Section 6(a).
“Designated Event” has the meaning specified in Section 5(b)(v).
“Determining Party” means the party determining a Close-out Amount.
“Early Termination Amount” has the meaning specified in Section 6(e).
“Early Termination Date” means the date determined in accordance with Section 6(a) or 6(b)(iv).
“electronic messages” does not include e-mails but does include documents expressed in markup languages, and “electronic messaging system” will be construed
accordingly.
“English law” means the law of England and Wales, and “English” will be construed accordingly.
“Event of Default” has the meaning specified in Section 5(a) and, if applicable, in the Schedule.
“Force Majeure Event” has the meaning specified in Section 5(b).
“General Business Day” means a day on which commercial banks are open for general business (including dealings in foreign exchange and foreign currency
deposits).
“Illegality” has the meaning specified in Section 5(b).
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“Indemnifiable Tax” means any Tax other than a Tax that would not be imposed in respect of a payment under this Agreement but for a present or former connection
between the jurisdiction of the government or taxation authority imposing such Tax and the recipient of such payment or a person related to such recipient (including,
without limitation, a connection arising from such recipient or related person being or having been a citizen or resident of such jurisdiction, or being or having been
organised, present or engaged in a trade or business in such jurisdiction, or having or having had a permanent establishment or fixed place of business in such
jurisdiction, but excluding a connection arising solely from such recipient or related person having executed, delivered, performed its obligations or received a payment
under, or enforced, this Agreement or a Credit Support Document).
“law” includes any treaty, law, rule or regulation (as modified, in the case of tax matters, by the practice of any relevant governmental revenue authority), and
“unlawful” will be construed accordingly.
“Local Business Day” means (a) in relation to any obligation under Section 2(a)(i), a General Business Day in the place or places specified in the relevant
Confirmation and a day on which a relevant settlement system is open or operating as specified in the relevant Confirmation or, if a place or a settlement system is not
so specified, as otherwise agreed by the parties in writing or determined pursuant to provisions contained, or incorporated by reference, in this Agreement, (b) for the
purpose of determining when a Waiting Period expires, a General Business Day in the place where the event or circumstance that constitutes or gives rise to the
Illegality or Force Majeure Event, as the case may be, occurs, (c) in relation to any other payment, a General Business Day in the place where the relevant account is
located and, if different, in the principal financial centre, if any, of the currency of such payment and, if that currency does not have a single recognized principal
financial centre, a day on which the settlement system necessary to accomplish such payment is open, (d) in relation to any notice or other communication, including
notice contemplated under Section 5(a)(i), a General Business Day (or a day that would have been a General Business Day but for the occurrence of an event or
circumstance which would, if it occurred with respect to payment, delivery or compliance related to a Transaction, constitute or give rise to an Illegality or a Force
Majeure Event) in the place specified in the address for notice provided by the recipient and, in the case of a notice contemplated by Section 2(b), in the place where the
relevant new account is to be located and (e) in relation to Section 5(a)(v)(2), a General Business Day in the relevant locations for performance with respect to such
Specified Transaction.
“Local Delivery Day” means, for purposes of Sections 5(a)(i) and 5(d), a day on which settlement systems necessary to accomplish the relevant delivery are generally
open for business so that the delivery is capable of being accomplished in accordance with customary market practice, in the place specified in the relevant
Confirmation or, if not so specified, in a location as determined in accordance with customary market practice for the relevant delivery.
“Master Agreement” has the meaning specified in the preamble.
“Merger Without Assumption” means the event specified in Section 5(a)(viii).
“Multiple Transaction Payment Netting” has the meaning specified in Section 2(c).
“Non-affected Party” means, so long as there is only one Affected Party, the other party.
“Non-default Rate” means the rate certified by the Non-defaulting Party to be a rate offered to the Non-defaulting Party by a major bank in a relevant interbank market
for overnight deposits in the applicable currency, such bank to be selected in good faith by the Non-defaulting Party for the purpose of obtaining a representative rate
that will reasonably reflect conditions prevailing at the time in that relevant market.
“Non-defaulting Party” has the meaning specified in Section 6(a).
“Office” means a branch or office of a party, which may be such party’s head or home office.
“Other Amounts” has the meaning specified in Section 6(f).
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“Payee” has the meaning specified in Section 6(f).
“Payer” has the meaning specified in Section 6(f).
“Potential Event of Default” means any event which, with the giving of notice or the lapse of time or both, would constitute an Event of Default.
“Proceedings” has the meaning specified in Section 13(b).
“Process Agent” has the meaning specified in the Schedule.
“rate of exchange” includes, without limitation, any premiums and costs of exchange payable in connection with the purchase of or conversion into the Contractual
Currency.
“Relevant Jurisdiction” means, with respect to a party, the jurisdictions (a) in which the party is incorporated, organised, managed and controlled or considered to have
its seat, (b) where an Office through which the party is acting for purposes of this Agreement is located, (c) in which the party executes this Agreement and (d) in
relation to any payment, from or through which such payment is made.
“Schedule” has the meaning specified in the preamble.
“Scheduled Settlement Date” means a date on which a payment or delivery is to be made under Section 2(a)(i) with respect to a Transaction.
“Specified Entity” has the meaning specified in the Schedule.
“Specified Indebtedness” means, subject to the Schedule, any obligation (whether present or future, contingent or otherwise, as principal or surety or otherwise) in
respect of borrowed money.
“Specified Transaction” means, subject to the Schedule, (a) any transaction (including an agreement with respect to any such transaction) now existing or hereafter
entered into between one party to this Agreement (or any Credit Support Provider of such party or any applicable Specified Entity of such party) and the other party to
this Agreement (or any Credit Support Provider of such other party or any applicable Specified Entity of such other party) which is not a Transaction under this
Agreement but (i) which is a rate swap transaction, swap option, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap,
equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, currency swap
transaction, cross-currency rate swap transaction, currency option, credit protection transaction, credit swap, credit default swap, credit default option, total return swap,
credit spread transaction, repurchase transaction, reverse repurchase transaction, buy/sell-back transaction, securities lending transaction, weather index transaction or
forward purchase or sale of a security, commodity or other financial instrument or interest (including any option with respect to any of these transactions) or (ii) which
is a type of transaction that is similar to any transaction referred to in clause (i) above that is currently, or in the future becomes, recurrently entered into in the financial
markets (including terms and conditions incorporated by reference in such agreement) and which is a forward, swap, future, option or other derivative on one or more
rates, currencies, commodities, equity securities or other equity instruments, debt securities or other debt instruments, economic indices or measures of economic risk or
value, or other benchmarks against which payments or deliveries are to be made, (b) any combination of these transactions and (c) any other transaction identified as a
Specified Transaction in this Agreement or the relevant confirmation.
“Stamp Tax” means any stamp, registration, documentation or similar tax.
“Stamp Tax Jurisdiction” has the meaning specified in Section 4(e).
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“Tax” means any present or future tax, levy, impost, duty, charge, assessment or fee of any nature (including interest, penalties and additions thereto) that is imposed by
any government or other taxing authority in respect of any payment under this Agreement other than a stamp, registration, documentation or similar tax.
“Tax Event” has the meaning specified in Section 5(b).
“Tax Event Upon Merger” has the meaning specified in Section 5(b).
“Terminated Transactions” means, with respect to any Early Termination Date, (a) if resulting from an Illegality or a Force Majeure Event, all Affected Transactions
specified in the notice given pursuant to Section 6(b)(iv), (b) if resulting from any other Termination Event, all Affected Transactions and (c) if resulting from an Event
of Default, all Transactions in effect either immediately before the effectiveness of the notice designating that Early Termination Date or, if Automatic Early
Termination applies, immediately before that Early Termination Date.
“Termination Currency” means (a) if a Termination Currency is specified in the Schedule and that currency is freely available, that currency, and (b) otherwise, Euro if
this Agreement is expressed to be governed by English law or United States Dollars if this Agreement is expressed to be governed by the laws of the State of New
York.
“Termination Currency Equivalent” means, in respect of any amount denominated in the Termination Currency, such Termination Currency amount and, in respect of
any amount denominated in a currency other than the Termination Currency (the “Other Currency”), the amount in the Termination Currency determined by the party
making the relevant determination as being required to purchase such amount of such Other Currency as at the relevant Early Termination Date, or, if the relevant
Close-out Amount is determined as of a later date, that later date, with the Termination Currency at the rate equal to the spot exchange rate of the foreign exchange
agent (selected as provided below) for the purchase of such Other Currency with the Termination Currency at or about 11:00 a.m. (in the city in which such foreign
exchange agent is located) on such date as would be customary for the determination of such a rate for the purchase of such Other Currency for value on the relevant
Early Termination Date or that later date. The foreign exchange agent will, if only one party is obliged to make a determination under Section 6(e), be selected in good
faith by that party and otherwise will be agreed by the parties.
“Termination Event” means an Illegality, a Force Majeure Event, a Tax Event, a Tax Event Upon Merger or, if specified to be applicable, a Credit Event Upon Merger
or an Additional Termination Event.
“Termination Rate” means a rate per annum equal to the arithmetic mean of the cost (without proof or evidence of any actual cost) to each party (as certified by such
party) if it were to fund or of funding such amounts.
“Threshold Amount” means the amount, if any, specified as such in the Schedule.
“Transaction” has the meaning specified in the preamble.
“Unpaid Amounts” owing to any party means, with respect to an Early Termination Date, the aggregate of (a) in respect of all Terminated Transactions, the amounts
that became payable (or that would have become payable but for Section 2(a)(iii) or due but for Section 5(d)) to such party under Section 2(a)(i) or 2(d)(i)(4) on or prior
to such Early Termination Date and which remain unpaid as at such Early Termination Date, (b) in respect of each Terminated Transaction, for each obligation under
Section 2(a)(i) which was (or would have been but for Section 2(a)(iii) or 5(d)) required to be settled by delivery to such party on or prior to such Early Termination
Date and which has not been so settled as at such Early Termination Date, an amount equal to the fair market value of that which was (or would have been) required to
be delivered and (c) if the Early Termination Date results from an Event of Default, a Credit Event Upon Merger or an Additional Termination Event in respect of
which all outstanding Transactions are Affected Transactions, any Early Termination Amount due prior to such Early Termination Date and which remains unpaid as
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of such Early Termination Date, in each case together with any amount of interest accrued or other compensation in respect of that obligation or deferred obligation, as
the case may be, pursuant to Section 9(h)(ii)(1) or (2), as appropriate. The fair market value of any obligation referred to in clause (b) above will be determined as of the
originally scheduled date for delivery, in good faith and using commercially reasonable procedures, by the party obliged to make the determination under Section 6(e)
or, if each party is so obliged, it will be the average of the Termination Currency Equivalents of the fair market values so determined by both parties.
“Waiting Period” means:—
(a) in respect of an event or circumstance under Section 5(b)(i), other than in the case of Section 5(b)(i)(2) where the relevant payment, delivery or compliance is
actually required on the relevant day (in which case no Waiting Period will apply), a period of three Local Business Days (or days that would have been Local Business
Days but for the occurrence of that event or circumstance) following the occurrence of that event or circumstance; and
(b) in respect of an event or circumstance under Section 5(b)(ii), other than in the case of Section 5(b)(ii)(2) where the relevant payment, delivery or compliance is
actually required on the relevant day (in which case no Waiting Period will apply), a period of eight Local Business Days (or days that would have been Local Business
Days but for the occurrence of that event or circumstance) following the occurrence of that event or circumstance.
IN WITNESS WHEREOF the parties have executed this document on the respective dates specified below with effect from the date specified on the first page of this
document.
MORGAN STANLEY CAPITAL GROUP INC.
CHESAPEAKE GRANITE WASH TRUST
By:
Name:
Title:
Date:
By:
Name:
Title:
Date:
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SCHEDULE
to the
2002 MASTER AGREEMENT
dated as of [Date]
between
MORGAN STANLEY CAPITAL GROUP INC.
a Delaware corporation
(“Party A”)
and
CHESAPEAKE GRANITE WASH TRUST
a Delaware statutory trust
(“Party B”)
Part 1. Termination Provisions.
(a) “Specified Entity” means:
in relation to Party A for the purpose of:
Section 5(a)(v) (Default Under Specified Transaction)
None Specified
Section 5(a)(vi) (Cross Default)
None Specified
Section 5(a)(vii) (Bankruptcy)
None Specified
Section 5(b)(v) (Credit Event Upon Merger)
None Specified
and in relation to Party B for the purpose of:
Section 5(a)(v) (Default Under Specified Transaction)
None Specified
Section 5(a)(vi) (Cross Default)
None Specified
Section 5(a)(vii) (Bankruptcy)
None Specified
Section 5(b)(v) (Credit Event Upon Merger)
None Specified
(b)
“Specified Transaction” has the meaning specified in Section 14 of the Agreement.
(c)
The “Cross Default” provisions of Section 5(a)(vi) of this Master Agreement will apply to both parties.
(d)
“Specified Indebtedness” has the meaning specified in Section 14 of this Agreement.
(e)
“Threshold Amount” means, with respect to a party, an amount equal to USD 10,000,000 (or the equivalent in another currency, currency unit or combination
thereof).
(f)
Credit Event Upon Merger applies to Party A and Party B.
(g)
The Automatic Early Termination provision of Section 6(a) of this Agreement will not apply to Party A and will not apply to Party B.
29
(h) “Termination Currency” means United States Dollars (“USD”).
(i)
Additional Termination Event will apply. Each of the following shall constitute an Additional Termination Event with respect to Party B, in which event Party
B shall be the sole Affected Party and all Transactions shall be Affected Transactions:
(i)
an event of default with respect to Party B occurs under any Credit Support Document or any Credit Support Document expires or terminates;
(ii)
either (1) in the requirements specified in Part 6(a)(i) of the Schedule fail to be met, or (2) the requirements specified in Part 6(a)(ii) of the Schedule fail to
be met in any material respect, and in either case such failure continues for 30 days;
(iii)
any other Master Agreement to which Party B is a party is terminated, in circumstances where Party B is the “Defaulting Party” or the sole “Affected
Party” as defined therein;
(iv)
the obligations of Party B hereunder cease to rank at least pari passu with the obligations of Party B under any other Master Agreement other than solely
as a result of actions of Party A;
(v)
the obligations of Party B hereunder cease to be secured, on an equal and ratable basis with the obligations of Party B under any other Master Agreement,
by the collateral that is Collateral under any Credit Support Document in each case other than solely as a result of actions of Party A;
(vi)
either (1) Party B or Chesapeake fails to perform any of its payment obligations under the Collateral Agency Agreement and such failure continues for two
Business Days after notice of such failure is delivered to Party B, or (2) Party B or Chesapeake fails to observe, perform, or fulfill any of the covenants,
terms, and provisions other than payment obligations applicable to it under the Collateral Agency Agreement and such failure continues for 30 days after
notice of such failure is delivered to Party B; and
(vii) all or substantially all of the collateral covered by the Collateral Agency Agreement is released for any reason whatsoever, in each case other than solely as
a result of actions of Party A.
(j)
Grace Periods. Section 5(a)(i) shall be modified in the third line thereof to delete the word “first” in the two places where it occurs and replace it with the word
“second”.
Section 5(a)(iii)(1) shall be modified to add the following proviso at the end thereof: “provided that such default continues for at least two Local Business Days”.
Part 2. Representations.
(a)
Party A and Party B Tax Representations. For the purpose of Section 3(e) of this Agreement, each of Party A and Party B makes the following representation:
It is not required by any applicable law, as modified by the practice of any relevant governmental revenue authority, of any Relevant Jurisdiction to make any
deduction or withholding for or on account of any Tax from any payment (other than interest under Section 9(h) of this Agreement) to be made by it to the other party
under this Agreement. In making this representation, it may rely on: (i) the accuracy of any representations made by the other party pursuant to Section 3(f) of this
Agreement; (ii) the satisfaction of the agreement contained in Sections 4(a)(i) or 4(a)(iii) of this Agreement and the accuracy and effectiveness of any document
provided by the other party pursuant to Sections 4(a)(i) or 4(a)(iii) of this Agreement; and (iii) the satisfaction of the agreement of the other
30
party contained in Section 4(d) of this Agreement, except that it will not be a breach of this representation where reliance is placed on clause (ii) and the other party
does not deliver a form or document under Section 4(a)(iii) of this Agreement by reason of material prejudice to its legal or commercial position.
(b)
(i)
For the purpose of Section 3(f) of this Master Agreement, Party A makes the following representations:
It is a corporation organized under the laws of the State of Delaware and is an exempt recipient under Section 1.6049-4(c)(1)(ii) of the United States Treasury
Regulations. Party A’s U.S. taxpayer identification number is 13-3200368.
(ii)
For the purpose of Section 3(f) of this Master Agreement, Party B makes the following representation:
It is a statutory trust organized under the laws of the State of Delaware and is a United States person for U.S. federal income tax purposes. Party B’s U.S. taxpayer
identification number is 73-1395733.
Part 3. Agreement to Deliver Documents.
For the purpose of Sections 4(a)(i) and (ii) of this Agreement, each party agrees to deliver the following documents, as applicable:
(a) Tax forms, documents or certificates to be delivered are:
Party required
to deliver
document
Party A and
Party B
Form/Document/Certificate
Date by which to be delivered
An executed United States Internal Revenue Service Form W-9 (or any
successor thereto).
(i) On a date which is before the first Scheduled Payment Date under this
Master Agreement, (ii) promptly upon reasonable demand by either party,
and (iii) promptly upon learning that any such form previously provided
by either party has become obsolete, incorrect or ineffective.
(b) Other documents to be delivered are:
Party required to
deliver document
Party A and Party B
Form/Document/Certificate
Date by which to be delivered
Certificate of authority and specimen signatures for
individuals executing this Master Agreement and any Credit
Support Document
Promptly upon execution of this Master Agreement, and
thereafter as soon as practicable following written demand
31
Covered by
Section 3(d)
Representation
Yes
Party required
to deliver document
Form/Document/Certificate
Date by which to be delivered
Covered by
Section 3(d)
Representation
Party B
A duly executed and delivered copy of each Credit Support
Document specified in Part 4(f) herein
Upon execution of this Master Agreement and from time
to time thereafter as and when required under the
Collateral Agency Agreement
Yes
Party A
A duly executed and delivered copy of each Credit Support
Document specified in Part 4(g) herein
Upon execution of this Master Agreement
Yes
Party A
Most recent, publicly available, annual audited consolidated
financial statement of Party A’s Credit Support Provider for
its most recently ended fiscal year, prepared in accordance
with generally accepted accounting principles in the country
in which such entity is organized and certified by
independent certified public accountants or chartered
accountants.
Where such financial statement is not reasonably publicly
available on “EDGAR” or Party A’s Internet home page,
promptly following reasonable demand by Party B after
being made publicly available
Yes
Party A
Copy of the most recent, publicly available interim report of
Party A’s Credit Support Provider containing unaudited
financial statements; prepared in accordance with generally
accepted accounting principles in the country in which such
party is organized
Where such financial statement is not reasonably publicly
available on “EDGAR” or such Credit Support Provider’s
Internet home page, promptly following reasonable
demand by Party B after being made publicly available
Yes
Party B
A copy of all relevant formation documents (such as
certificate of formation and trust agreement), disclosure
documents (such as offering memorandum), a list of all
principals (such as directors / trustees / general partners) (in
each case as may be amended from time to time), the
government-issued or taxpayer identification number (as
applicable), and any other documentation required to meet
customer identification program requirements.
The earlier of (i) execution of this Agreement and (ii) the
trade date of the first Transaction and as deemed necessary
for any further documentation.
Yes
32
Party required
to deliver document
Form/Document/Certificate
Date by which to be delivered
Covered by
Section 3(d)
Representation
Party B
The Reserve Report and Drilling Report (as described in
Parts 6(b) and 6(c) of this Schedule).
As required by Part 6(b) and 6(c) of this Schedule.
Yes
Party A and Party B
Such other documents as the other party may reasonably
request.
Upon request
No
Part 4. Miscellaneous.
(a)
Addresses for Notices. For the purpose of Section 12(a) of this Agreement:
(i)
Address for notices or communications to Party A:
For notices or communications with respect to Section 5 or 6 only:
c/o Morgan Stanley & Co. LLC
1585 Broadway
New York, New York 10036-8293
Attention:
Close-out Notices
With a mandatory copy to:
Facsimile No.: +1 212 507 4622
For notices or communications with respect to all purposes other than Section 5 or 6:
c/o Morgan Stanley & Co. LLC
1585 Broadway
New York, New York 10036-8293
Attention:
Miscellaneous Notices
Facsimile No.:
+1 212 404 9899
(ii)
Address for notices or communications to Party B:
Chesapeake Granite Wash Trust
c/o The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue, Suite 500
Austin, Texas 78701
Attention:
Michael J. Ulrich
Telephone No.: (512) 236-6599
Facsimile No.: (512) 236-9275
(b)
Process Agent. For the purpose of Section 13(c) of this Agreement:
(i)
Party A irrevocably appoints as its Process Agent: Not Applicable
(ii)
Party B irrevocably appoints as its Process Agent: Not Applicable
(c)
Offices. The provisions of Section 10(a) of this Agreement will apply to Party A and will apply to Party B.
(d)
Multibranch Party. For the purpose of Section 10(b) of this Agreement:
33
Party A is not a Multibranch Party.
Party B is not a Multibranch Party
(e)
“Calculation Agent” means Party A; provided, however, that if an Event of Default shall occur and be continuing under which Party A is the Defaulting Party,
then the Calculation Agent will be Party B for so long as Party A is a Defaulting Party.
(f)
“Credit Support Document” means with respect to the obligations of Party B: (i) the Mortgage, (ii) Collateral Agency Agreement, and (iii) the Credit Support
Annex attached hereto.
(g)
“Credit Support Document” means, with respect to the obligations of Party A: (i) the Credit Support Annex attached hereto, and (ii) a Guarantee, made by
Morgan Stanley in favor of Party B as beneficiary thereof.
(h)
“Credit Support Provider” means in relation to Party A: Morgan Stanley, a Delaware corporation.
(i)
“Credit Support Provider” means in relation to Party B: not applicable.
(j)
“Mortgage” means the Mortgage dated as of
(k)
Governing Law; Jurisdiction. Sections 13(a) and (b) of the Agreement shall be deleted and replaced with the following:
“(a)
(b)
, 2011 by Party B in favor of the Collateral Agent.
Governing Law. This Agreement will be governed by and construed in accordance with the laws of the State of New York.
Jurisdiction. With respect to any suit, action or proceedings relating to any dispute arising out of or in connection with this Agreement (“Proceedings”),
each party:
(i)
irrevocably submits to the exclusive jurisdiction of the courts of the State of New York and the United States District Court located in the
Borough of Manhattan in New York City of the State of New York; and
(ii)
waives any objection which it may have at any time to the laying of venue of any Proceedings brought in any such court, waives any claim that
such Proceedings have been brought in an inconvenient forum and further waives the right to object, with respect to such Proceedings, that such
court does not have any jurisdiction over such party.”
Nothing in this Agreement precludes either party from bringing Proceedings in any other jurisdiction if:
(A)
the courts of the State of New York or the United States District Court located in the Borough of Manhattan in New York City lacks jurisdiction
over the parties or the subject matter of the Proceedings or declines to accept the Proceedings on the grounds of lacking such jurisdiction;
(B)
the Proceedings are commenced by a party for the purpose of enforcing against the other party’s property, assets or estate any decision or
judgment rendered by any court in which Proceedings may be brought as provided hereunder;
(C)
the Proceedings are commenced to appeal any such court’s decision or judgment to any higher court with competent appellate jurisdiction over
that court’s decisions or
34
judgments if that higher court is located outside the State of New York or Borough of Manhattan, such as a federal court of appeals or the U.S.
Supreme Court; or
(D)
any suit, action or proceeding has been commenced in another jurisdiction by or against the other party or against its property, assets or estate
(including, without limitation, any suit, action or proceeding described in Section 5(a)(vii)(4) of this Agreement), and, in order to exercise or
protect its rights, interests or remedies under this Agreement, the party (1) joins, files a claim, or takes any other action, in any such suit, action or
proceeding, or (2) otherwise commences any Proceeding in that other jurisdiction as the result of that other suit, action or proceeding having
commenced in that other jurisdiction.”
(l)
Waiver of Jury Trial. Each party waives, to the fullest extent permitted by applicable law, any right it may have to a trial by jury in respect of any Proceedings
relating to this Agreement or any Credit Support Document.
(m)
Netting of Payments. “Multiple Transaction Payment Netting” will apply for the purpose of Section 2(c) of this Agreement to all Transactions under this
Agreement.
(n)
“Affiliate” has the meaning specified in Section 14 of this Agreement, but excludes Morgan Stanley Derivative Products Inc.
(o)
Absence of Litigation. For the purpose of Section 3(c) of this Agreement “Specified Entity” shall mean Affiliates in relation to both parties.
(p)
No Agency. The provisions of Section 3(g) will apply to this Agreement.
(q)
Additional Representation will apply. For the purpose of Section 3 of this Agreement the following Section 3(h) will constitute an Additional Representation:
(h)
Relationship Between Parties. Each party will be deemed to represent to the other party on the date on which it enters into a Transaction that (absent a
written agreement between the parties that expressly imposes affirmative obligations to the contrary for that Transaction):
(1)
Non-Reliance. It is acting for its own account, and it has made its own independent decisions to enter into that Transaction and as to whether that
Transaction is appropriate or proper for it based upon its own judgment and upon advice from such advisers as it has deemed necessary. It is not
relying on any communication (written or oral) of the other party as investment advice or as a recommendation to enter into that Transaction, and
the other party is not acting with respect to any communication (written or oral) as a “municipal advisor,” as such term is defined in Section 975
of the U.S. Dodd-Frank Wall Street Reform & Consumer Protection Act; it being understood that information and explanations related to the
terms and conditions of a Transaction shall not be considered investment advice, advice provided by a municipal advisor or a recommendation to
enter into that Transaction. No communication (written or oral) received from the other party shall be deemed to be an assurance or guarantee as
to the expected results of that Transaction;
(2)
Assessment and Understanding. It is capable of assessing the merits of and understanding (on its own behalf or through independent
professional advice), and understands and accepts, the terms, conditions and risks of that Transaction. It is also capable of assuming, and assumes,
the risks of that Transaction; and
(3)
Status of Parties. The other party is not acting as a fiduciary for or an adviser to it in respect of that Transaction.
35
(r)
Recording of Conversations. Each party (i) consents to the recording of telephone conversations between the trading, marketing and other relevant personnel of
the parties in connection with this Agreement or any potential Transaction, (ii) agrees to obtain any necessary consent of, and give any necessary notice of such
recording to, its relevant personnel and (iii) agrees, to the extent permitted by applicable law, that recordings may be submitted in evidence in any Proceedings.
Part 5. Other Provisions.
(a)
Additional Representations. In addition to the provisions addressed above in Part 4 of the Schedule, Section 3 of this Agreement is hereby amended by adding
at the end thereof the following sub-paragraphs:
(i)
Non-ERISA Representation. It continuously represents that it is not (i) an employee benefit plan (hereinafter an “ERISA Plan”), as defined in
Section 3(3) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), subject to Title I of ERISA or a plan subject to
Section 4975 of the Internal Revenue Code of 1986, as amended, or subject to any other statute, regulation, procedure or restriction that is materially
similar to Section 406 of ERISA or Section 4975 of the Code (together with ERISA Plans, “Plans”), (ii) a person any of the assets of whom constitute
assets of a Plan, or (iii) in connection with any Transaction under this Agreement, a person acting on behalf of a Plan, or using the assets of a Plan. It will
provide notice to the other party in the event that it is aware that it is in breach of any aspect of this representation or is aware that with the passing of time,
giving of notice or expiry of any applicable grace period it will breach this representation.
(ii)
Eligible Contract Participant. It is an “Eligible Contract Participant” as defined in Section 1a(18) of the Commodity Exchange Act, as amended.
(b)
2005 Commodity Definitions. This Master Agreement and each Transaction are subject to the 2005 ISDA Commodity Definitions (the “Commodity
Definitions”), as published by the International Swaps and Derivatives Association, Inc. and will be governed by the provisions of the Commodity Definitions.
The provisions of the Commodity Definitions are incorporated by reference in, and shall form part of, this Master Agreement and each Confirmation. Any
reference to a “Swap Transaction” in the Commodity Definitions is deemed to be a reference to a “Transaction” for purposes of this Master Agreement or any
Confirmation, and any reference to a “Transaction” in this Master Agreement or any Confirmation is deemed to be a reference to a “Swap Transaction” for
purposes of the Commodity Definitions. The provisions of this Master Agreement (exclusive of the Commodity Definitions) shall prevail in the event of any
conflict between such provisions and the Commodity Definitions. In the event of any inconsistency between the provisions of any Confirmation and this Master
Agreement or the Commodity Definitions, such Confirmation will prevail for the purpose of the relevant Transaction.
(c)
Scope of Agreement. This Master Agreement shall apply only to Covered Transactions entered into between Party A and Party B.
(d)
Procedures for Entering Into Transactions. Party A will deliver to Party B a Confirmation relating to each Transaction.
(e)
Form of Agreement. The parties hereby agree that the text of the body of the Agreement is intended to be the printed form of 2002 ISDA Master
Agreement as published and copyrighted by the International Swaps and Derivatives Association, Inc.
(f)
Conditions Precedent. Section 2(a)(iii)(1) of the Agreement shall be modified to insert the words “Additional Termination Event” after the words “Event of
Default” in line 2 thereof.
36
Section 2(a)(iii) is further amended by the insertion of the following sentence at the end of the existing provision:
“Any obligation of a party that is deferred in accordance with this Section 2(a)(iii) shall become due upon satisfaction of the relevant condition precedent.”
(g)
Collateral Agency Agreement.
(i)
Party B hereby acknowledges that Party A is a secured party under the Collateral Agency Agreement with respect to this Master Agreement.
(ii)
On the date Party B executes and delivers this Master Agreement and on each date on which a Transaction is entered into, Party B hereby represents and
warrants to Party A that: the Collateral Agency Agreement is in full force and effect; Party B is not party to any separate agreement with any of the parties
to the Collateral Agency Agreement that would have the effect of diminishing or impairing the rights, interests or benefits that have been granted to Party
A under, and which are expressly set forth in, the Collateral Agency Agreement; this Master Agreement constitutes a “Approved Swap Agreement” under
the Collateral Agency Agreement, and; Party A constitutes a “Swap Counterparty” under the Collateral Agency Agreement. In addition, on each date on
which a Transaction is entered into, Party B hereby represents and warrants to Party A that: Party B’s obligations under this Master Agreement are secured
under the Credit Support Documents, and neither the consent of Collateral Agent nor any of the Swap Counterparties (other than Party A) is required for
Party B to enter into that Transaction or for Party A to be entitled with respect to that Transaction to the rights, interests and benefits granted to Party A
under the Collateral Agency Agreement.
(h)
Consent to Notice and Communications. Party B hereby consents to Party A at any time providing the Collateral Agent with copies of this Master Agreement,
excluding Confirmations. In addition, Party A shall not be precluded from communicating with the Collateral Agent or any party to, or any third party
beneficiary under, the Collateral Agency Agreement for the purpose of exercising, enforcing or protecting any of Party A’s rights or remedies under this Master
Agreement or any rights, interests or benefits granted to Party A under the Collateral Agency Agreement.
(i)
Applicable Rate, Etc. For purposes of this Agreement, in no event shall the interest rate payable by Party B on any amounts owing by it hereunder exceed three
month LIBOR (as determined from time to time) plus 2% per annum.
(j)
2002 Master Agreement Protocol. The parties agree that the definitions and provisions contained the 2002 Master Agreement Protocol, as published on 15 July
2003 by The International Swaps and Derivatives Association Inc., are incorporated into and apply to this Agreement as if set out in full herein, for the purpose
of indicating agreement by the parties to the amendments set out in Annexes 1 to 18 of the Protocol. References in the Protocol to a 2002 Master shall be deemed
to be a reference to this Agreement.
Part 6. Additional Provisions.
Certain Definitions. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any
pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, and “including” shall be deemed to be followed by the phrase
“without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. The term “date hereof” refers to the date first
written above. Unless the context requires otherwise, (1) any definition of or reference to any agreement, instrument or other document herein shall be construed as
referring to such agreement, instrument or other document as from time to time amended, restated, supplemented or otherwise modified (subject to any restrictions on
such amendments, restatements, supplements or modifications set forth therein or herein), (2) references
37
to any law, constitution, statute, treaty, regulation, rule or ordinance, including any section or other part thereof (each for purposes of this paragraph, a “law”), shall
refer to that law as amended from time to time and shall include any successor law, (3) any references herein to any Person shall be construed to include such Person’s
successors and permitted assigns, (4) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its
entirety and not to any particular provision hereof and (5) all references herein to Sections, Parts, Annexes, Schedules and Exhibits shall be construed to refer to
Sections and Parts of, and Annexes, Schedules and Exhibits to, this Agreement.
As used herein, the following terms have the meanings given to them below:
“Chesapeake” means Chesapeake Energy Corporation, or any successor thereto or assign thereof that is reasonably satisfactory to Party A.
“Closing Date” means
, 2011.
“Collateral Agency Agreement” means that certain collateral agency agreement dated as of the Closing Date among Party A, Party B, the Collateral Agent and
each of the other parties to “Approved Swap Agreements” referred to therein.
“Collateral Agent” has the meaning set forth in the Credit Support Annex attached hereto.
“Covered Transaction” means a Transaction under this Agreement, dated as of [
, 2011] that is an over-the-counter commodity derivative that conforms
to the requirements of “Approved Swap Agreement” as set out in the Collateral Agency Agreement.
“Cumulative Minimum Well Requirement” shall have the meaning set forth in Part 6(a).
“Drilling Report” shall have the meaning set forth in Part 6(c).
“Independent Engineer” shall mean Ryder Scott Company, L.P. or such other independent third-party engineering firm as may be reasonably acceptable to
Party A that, at the time of the applicable Reserve Report, has been engaged by Party B to provide the independent reserve engineers reports for Party B in connection
with its SEC reporting obligations.
“Master Agreement” means a master agreement on the form of the 2002 ISDA Master Agreement, containing substantially the same terms as this Agreement,
forming a part of an “Approved Swap Agreement” under the Collateral Agency Agreement.
“Person” means an individual, corporation (including a business trust), partnership, limited liability company, limited liability partnership, joint venture,
association, joint stock company, trust (including any beneficiary thereof), unincorporated association or government or any agency or political subdivision thereof.
“Reasonably Prudent Operator Standard” means the standard of conduct of a reasonably prudent oil and gas operator under the same or similar circumstances,
acting with respect to its own property, disregarding the existence of Party B’s royalty interests as burdens on such properties.
“Reference Period” means each period commencing on the Closing Date and ending on a “Reference Period End Date” in the table set forth in Part 6(a)(i).
“Reserve Report” shall have the meaning set forth in Part 6(b).
“Underlying Properties” means the producing wells and development wells in Washita County, Oklahoma in which Party B owns royalty interests.
38
(a)
Drilling Covenants.
(i) From the Closing Date until June 30, 2016, Chesapeake shall drill and complete, or cause to be drilled and completed, or participate as a non-operator in the drilling
of, the development wells in accordance with the drilling plan set forth hereunder (the “ Cumulative Minimum Well Requirement ”).
Cumulative Minimum Well
Requirement
Reference Period End Date
December 31, 2011
June 30, 2012
December 31, 2012
June 30, 2013
December 31, 2013
June 30, 2014
December 31, 2014
June 30, 2015
December 31, 2015
June 30, 2016
38
52
69
78
85
90
97
108
111
117
For the avoidance of doubt, the number of Producing Wells (as defined in the Party B’s prospectus dated [
Date shall be included in the cumulative number of wells drilled and completed under this Section 6(a)(i).
], 2011 for its initial public offering) as of the Closing
(ii) In drilling the development wells: (1) Chesapeake shall drill and complete the development wells in a manner consistent with the manner in which the Producing
Wells (as defined in the Party B’s prospectus dated
, 2011 for its initial public offering) were drilled, (2) Chesapeake shall equip for production each
development well that is successfully completed, shall use commercially reasonable best efforts to connect such well to a gathering line, pipeline or other storage or
marketing facility and, when such well is equipped and connected to a gathering line, pipeline or other storage or marketing facility, shall commence production, and
(3) in any event, Chesapeake shall act in accordance with the Reasonably Prudent Operator Standard.
(b)
Engineering Reports. Party B hereby agrees to cause the Independent Engineer to deliver to the Collateral Agent and to Party A, promptly following the end of
each Reference Period, a reserve engineers’ report (a “ Reserve Report ”) that sets forth the total reserves estimated to be attributable to Party B’s interest in the
Underlying Properties (as defined in Party B’s prospectus dated
, 2011 for its initial public offering) as of the end of such Reference Period and such
other information as is typically included in, or required under SEC rules to be included in, reserve engineers reports; provided that each Reserve Report as of
December 31 shall be delivered to Party A on or before the date on which the Trust’s Annual Report on Form 10-K relating to the most recently completed year
is required to be filed with the SEC and that each Reserve Report as of June 30 shall be delivered to Party A on or before the date on which a similar reserve
report as of June 30 is required to the delivered by Chesapeake to its counterparties under its multi-party hedging facility (dated February 4, 2011) or, if no such
requirement exists, on or before August 31.
(c)
Factual Drilling Reports. Party B hereby agrees to deliver to Collateral Agent and to Party A, promptly after (but in no event later than 45 days following) the
end of each Reference Period, a report (a “ Drilling Report ”) that sets forth (i) the total number of development wells drilled and completed during such
Reference Period, and (ii) the total number of development wells drilled and completed since the Closing Date.
39
IN WITNESS WHEREOF, the parties have executed this Schedule by their duly authorized officers as of the date hereof.
MORGAN STANLEY CAPITAL GROUP INC.
CHESAPEAKE GRANITE WASH TRUST
By:
By:
Name:
Title:
Date:
Name:
Title:
Date:
40
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the use in Amendment #3 to the Registration Statements (No. 333-175395) on Form S-1/A of Chesapeake Granite Wash Trust and Form S-3 of
Chesapeake Energy Corporation of our report dated July 7, 2011 relating to the statements of revenues and direct operating expenses of the Chesapeake Granite Wash
Underlying Properties and our report dated July 7, 2011 relating to the statement of assets and trust corpus of Chesapeake Granite Wash Trust, both of which appear in
such Registration Statement.
We also hereby consent to the incorporation by reference in Amendment #3 to the Registration Statements (No. 333-175395) on Form S-1/A of Chesapeake Granite
Wash Trust and Form S-3 of Chesapeake Energy Corporation of our report dated March 1, 2011 relating to the financial statements, financial statement schedule, and
the effectiveness of internal control over financial reporting, which appears in Chesapeake Energy Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2010.
We also hereby consent to the reference to us under the heading “Experts” in such Registration Statement.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
October 17, 2011
Exhibit 23.2
CONSENT OF RYDER SCOTT COMPANY, L.P.
As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the inclusion of all references to our firm and our reports on reserves, as
of June 30, 2011, of the Underlying Properties and royalty interests to be conveyed to Chesapeake Granite Wash Trust as an annex to the prospectus included in this
Registration Statement on Form S-1 of Chesapeake Granite Wash Trust and Form S-3 of Chesapeake Energy Corporation to be filed on or about October 13, 2011, and
to the incorporation by reference in such Registration Statement of all references to our firm and information from our reserves report dated February 2, 2011, entitled
“Chesapeake Energy Corporation Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests SEC Parameters as of December 31,
2010,” included in or made a part of Chesapeake Energy Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010. We also consent to the
reference to us under the heading “Experts” in such Registration Statement.
/s/ Ryder Scott Company, L.P.
Ryder Scott Company, L.P.
TBPE Registration No. F-1580
Houston, Texas
October 17, 2011