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POSITIONED FOR SUSTAINABLE
LONG TERM VALUE CREATION
Corporate Presentation – August 2017
Advisories
FORWARD LOOKING STATEMENTS: In the interest of providing Bellatrix’s shareholders and potential investors with information regarding Bellatrix, including management’s assessment of Bellatrix’s future plans and operations, certain statements contained in these presentation materials (collectively, this
“presentation”) are forward looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward looking statements”. The forward looking statements contained in this presentation speak only as of the date of this presentation and are expressly
qualified by this cautionary statement. Forward looking statements in this presentation include, but are not limited to: statements regarding the quality of the Company’s assets and acreage, the Company’s infrastructure and firm transportation capacity, including the expected timing of completion of Phase 2 of
the Alder Flats Gas Plant, the Company’s growth plans and forecasted capital efficiencies and investment returns, the Company’s balance sheet and available liquidity, future production estimates, future drilling locations, 2017 guidance relating to production, production mix, net capital expenditures and
production expense, the Company’s net asset value, the Company’s acreage position, the nature and profitability of the Company’s Spirit River acreage, well results, the sustainability of cost reductions, drilling times and capital efficiencies, development metrics, future drilling inventory, the Company’s land
position, and the sufficiency and performance of the Company’s infrastructure. To the extent that any forward-looking information contained herein constitute a financial outlook, they were approved by management on August 9, 2017 and are included herein to provide readers with an understanding of the
anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes. Forward looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation,
production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to
realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, actions taken by the Company's lenders that reduce the Company's available credit and ability to access sufficient capital from internal and external sources. Events or circumstances may
cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward looking statements or information are based on a number of factors and
assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations. Such information may
prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements
because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and
political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an
interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs
of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the
Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the
forward-looking statements. Additional information on these and other factors that could affect Bellatrix’s operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through
the SEC website (www.sec.gov), and at Bellatrix’s website (www.bellatrixexploration.com). Furthermore, the forward looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward looking
statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
NON-GAAP MEASURES
Throughout this presentation, the Company uses terms that are commonly used in the oil and natural gas industry, but do not have a standardized meaning presented by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to the calculations of similar measures for other
entities. Management believes that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.
CAPITAL PERFORMANCE MEASURES
In addition to the non-GAAP measures described above, there are also terms that have been reconciled in the Company’s financial statements to the most comparable IFRS measures. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the
calculations of similar measures for other entities. These terms are used by management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Company.
This presentation contains the term “total net debt” which is not recognized measures under GAAP. Therefore reference to total net debt may not be comparable with the calculation of a similar measure for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred
capital obligations, long-term risk management contract liabilities, decommissioning liabilities, and deferred tax liabilities. Total net debt includes the working capital deficiency, long term loans receivable, convertible debentures (liability component), current bank debt and long term bank debt.
DRILLING LOCATIONS
In this presentation, the Company has disclosed certain drilling locations associated with Bellatrix's interest in the Spirit River and Cardium plays. Of the 381 net Spirit River drilling locations identified herein, 86 are proved locations, 30 are probable locations and 265 are unbooked locations. Of the 206 net
Cardium drilling locations identified herein, 92 are proved locations, 29 are probable locations, and 85 are unbooked locations. Proved locations and probable locations are derived from Bellatrix’s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31, 2016 and account for
drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked
locations do not have attributed reserves or resources. Unbooked locations as disclosed herein have been identified by management as an estimation of the Company's multi-year drilling activities using information including applicable geologic, seismic, engineering, production, pricing assumptions and reserves
information. There is no certainty that Bellatrix will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which Bellatrix actually drill wells will ultimately depend upon the availability of
capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of Bellatrix's unbooked locations are extensions or infills of the drilling patterns already recognized by the Company's
independent qualified reserves evaluator, other unbooked drilling locations are farther away from existing wells where management may have less information about the characteristics of the reservoir and therefore there may be more uncertainty whether wells will be drilled in such locations and if drilled there
may be more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
INITIAL RATES OF PRODUCTION
References in this presentation to initial production rates associated with certain wells are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term
performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. The Company cautions that such production rates should be considered to be preliminary.
BOE PRESENTATION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/ 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe
conversions in this presentation are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.
ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented which are based on the assumptions used by InSite Petroleum Consultants Ltd. to estimate Bellatrix's proved plus probable reserves
per well as evaluated effective December 31, 2016 based on forecast prices and costs. There is no certainty that such Bellatrix will ultimately recover such volumes from the wells it drills.
CURRENCY: All dollar amounts in this presentation are Canadian dollars unless otherwise identified.
RESERVES INFORMATION: Unless indicated otherwise, reserve estimates and related future net revenue and other reserves information is derived from Bellatrix’s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31, 2016 using forecast prices and costs. Land acreage
information is as available at December 31, 2016, unless otherwise noted.
TYPE CURVE AND CAPITAL EFFICIENCY: In this presentation information relating to the type curve, half cycle economics and capital efficiency for Bellatrix's Spirit River wells have been presented. The type curve set forth herein is based on all Bellatrix operated, Notikewin and Falher B wells drilled between
October 2012 and September 2015, and represents the mean (P50) performance curve. Half cycle economics are based on Bellatrix's current expectations of drill, complete, equip and tie-in costs per well (and excluding land, seismic and related costs). Capital efficiency is a measure of expected capital
expenditures per well based on half cycle economics divided by average first year production results (IP365) based on the type curve presented. The type curve and capital efficiency numbers have been presented to provide readers with information on the assumptions used for management's budgeting process
and future planning. The half cycle economics and capital efficiencies may not be achieved on future wells as a result of a number of factors including the risks identified above under "Forward Looking Statements" and as such are not reliable indicators of future performance. In addition, there is no certainty that
future wells will generate results to match historic type curves presented herein. Half cycle economics and capital efficiencies are not terms that have standardized meanings and therefore such calculations may not be comparable with the calculation of similar measures for other entities.
FINANCIAL INFORMATION: Unless otherwise stated, financial information is based upon Bellatrix’s audited consolidated financial statements for the years ended December 31, 2016 and 2015.
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Corporate Profile
MARKET SUMMARY
TSX / NYSE: BXE
Average Daily Volume1
Canada: ~165,000/ U.S.: ~100,000
Shares Outstanding2
49.4 million basic / 51.2 million diluted
Market Capitalization3
$162 million
Bank Debt4
$13 million
Senior Notes due 2020
US$250 million
Convertible Debentures
$50 million
Enterprise Value3
$545 million
2016 Exit Production
31,500 boe/d
2017 Estimated Exit Production
36,500 boe/d
2016 Exit to 2017 Exit Growth
>15%
2017 Natural Gas Weighting
76%
Three month average at August 8, 2017
Share count at July 6, 2017 (post consolidation). Diluted shares include options but exclude shares potentially issuable on conversion of
convertible debentures as the convertible debentures are included in the net debt calculation
3 Calculated using August 8, 2017 share price (C$3.27/share). Enterprise value includes market capitalization plus total net debt of $383
million as at June 30, 2017. Total net debt includes bank debt, $16 million adjusted working capital deficiency, the liability component of
the convertible debentures, and assumes conversion of US notes at Cdn/US $1.2983 as at June 30, 2017.
4 Bank debt reflects $13 million outstanding on the Credit Facilities at June 30, 2017
1
2
3
Ticker Symbol
Investment Highlights
HIGH QUALITY
ASSETS &
ACREAGE
•
•
•
•
Dominant core acreage position in west central Alberta
Spirit River represents one of North America’s lowest supply cost natural gas plays
Consistently deliver top ranked well productivity results
Asset portfolio provides balance of natural gas and oil/liquids weighted opportunities
INFRASTRUCTURE
OWNERSHIP &
CONTROL
•
Ownership and control of strategic infrastructure including pipelines, compression, and
processing facilities
Infrastructure control creates significant barriers to competition within core area
TAKEAWAY
CAPACITY &
MARKET EGRESS
•
PROFITABLE
GROWTH
STRONG
LIQUIDITY
4
•
•
•
•
•
•
•
•
•
Secured firm transportation over approximately 120% of current gross operated natural
gas volumes
Maintain firm service contracts through owned & third party processing plants
Long term NGL fractionation agreements in place for 100% of volumes
Defined three year outlook provides line of sight for +/-15% compound annual
production volume growth
Top tier capital efficiencies and cost profile deliver full cycle sustainable profitability
Current commodity prices drive strong forecast investment returns
89% unused capacity on bank credit facilities at June 30, 2017
Liquidity enhanced on May 9, 2017 with bank credit facilities increasing to $120 million
(from $100 million) and reconfirmed at $120 million post-closing of Strachan asset sale
No term debt maturities until May 2020 and September 2021
Note: 89% unused capacity on bank credit facilities at June 30, 2017 and references $13 million bank debt relative to credit facilities of $120 million. Unused capacity excludes outstanding
letters of credit.
Reintroducing Bellatrix
NEW LEADERSHIP
•
Brent Eshleman appointed President, CEO and a member of the Board of Directors on February 15, 2017
•
Max Lof appointed Executive Vice President & CFO on June 19, 2017
TRANSFORMATIONAL CHANGES COMPLETED IN 2016 & 2017
Strategic repositioning efforts completed which includes increased asset concentration, a materially
stronger balance sheet and an enhanced net asset value
•
June 30, 2017
January 1, 2016
Change
Total net debt
$383 million
$718 million
Reduced 46%
Bank debt
$13 million
$341 million
Reduced 96%
Core areas = 99% of
total production
Core areas = 83% of
total production
Sold Strachan,
Harmattan &
Pembina Cardium
Sharpening our focus on the
highest value core assets1
Current core area (Greater Ferrier, Willesden Green & Pembina areas) production % of total based on first week of August 2017 field level estimates; year end 2015 core area production
based on January 2016 field estimates.
1
5
Production (boe/d)
Maintain Production Volumes While
Achieving Significant Debt Reduction
Average
Production
Flat Q1/16
to Q2/17
40,000
30,000
20,000
10,000
0
Q1/16
Q2/16
Q3/16
Q4/16
Q1/17
Q2/17
$800
Debt ($MM)
$700
$600
Total
Net Debt
Reduced
46% from
Q1/16 to
Q2/17
$500
$400
$300
$200
$100
$0
Q1/16
Q2/16
Net Bank Debt
6
Q3/16
Q4/16
U.S. Senior Notes
Q1/17
Convertible Debentures
Net bank debt includes bank debt outstanding and working capital deficiency; convertible debentures include liability component
Q2/17
Material Deleveraging & Strategic
Repositioning
SUCCESSFULLY RAISED APPROXIMATELY $440 MILLION IN THE PAST 16 MONTHS OVER
MULTIPLE TRANSACTIONS WITH MINIMAL PRODUCTION DIVESTED
#
Transaction
1
Facilities monetization
2
Announcement Gross Proceeds Production sold
Date
boe/d
$MM
13-May-16
$75
0
35% Alder Flats Plant sale
07-Jul-16
$113
0
3
Bought deal financings
19-Jul-16
$80
0
4
Pembina non-core asset sale
19-Sep-16
$47
930
5
CDE Flow-through financing
04-Oct-16
$10
0
6
Harmattan non-core asset sale
05-Dec-16
$80
3,076
7
Strachan non-core asset sale
14-Jun-17
$35
1,750
$440
5,756
Total
FOCUS REMAINS ON STRATEGIC POSITIONING AND CORE VALUE OPTIMIZATION
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Note: Bought deal financings refer to the issuance of $50 million aggregate principal amount of 6.75% extendible unsecured subordinated convertible debentures and 25,000,000 subscription
receipts (subsequently converted into common stock of Bellatrix) for aggregate gross proceeds of $80 million as announced on July 19, 2016
CDE flow-through financing refers to private placement “flow-through” basis in respect of Canadian Development Expenses (“CDE”) resulting in gross proceeds of $10 million announced on
October 4, 2016
Balance Sheet & Financial Flexibility
Effective capital resource management, balancing liquidity and flexibility
Debt maturities (C$)
Q2/17
Q1/17
LONGER DATED TERM DEBT
MATURITIES
$350
$300
$250
$200
$150
$100
$50
$0
2017 2018 2019 2020 2021
Bank debt $13MM at
June 30, 2017
One financial covenant is Senior
Debt/EBITDA
Bellatrix has no term debt
maturities until 2020 & 2021.
$120MM credit facility at
May 9, 2017 (increased by $20
million from previous levels)
Maximum Senior Debt/EBITDA
ratio of 3.0x
US$250MM notes
(C$315MM at June 30, 2017)
mature May 15, 2020
Next semi-annual
redetermination November
2017
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Q4/16
Undrawn
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
Q3/16
Utilized
CREDIT FACILITY CONTAINS
ONE FINANCIAL COVENANT
Senior Debt/EBITDA
BANK DEBT $13MM
AT JUNE 30, 2017
1
Q2/17 ratio was 1.06x well
below financial covenant
$13 million outstanding on the Credit Facilities (before deducting outstanding letters of credit) at June 30, 2017
C$50MM convertible debenture
mature Sept 30, 2021
2017 Outlook & Guidance
INITIAL
2017 ANNUAL
GUIDANCE
(JANUARY 5, 2017)
PREVIOUSLY SET
2017 ANNUAL
GUIDANCE
(JUNE 26, 2017)
REVISED
CHANGE
2017 ANNUAL
FROM INITIAL
GUIDANCE
(AUGUST 10, 2017)
33,500
35,000
34,500
35,500
36,000
36,500
+/-15%
+/-15%
>15%
76
24
76
24
76
24
Total net capital expenditures1
$105.0
$120.0
$120.0
Property disposition – cash2
Total net capital expenditures
after property disposition - cash
Expenses
Production expense ($/boe)3
-
($34.5)
($34.5)
$105.0
$85.5
$85.5
$19.5
$9.00
$9.00
$8.75
$0.25
Production (boe/d)
2017 Average daily production
2017 Exit production
2017 Growth (2016 exit to 2017
exit)
Production mix (%)
Natural gas
Crude oil, condensate and NGLs
Capital Expenditures ($MM)
Net capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions. Net capital spending also excludes the
previously received prepayment portion of Bellatrix's partner’s 35% share of the cost of construction of Phase 2 of the Alder Flats Plant during calendar 2017.
2 Property disposition – cash refers to the Strachan asset sale and does not include transaction costs or adjustments.
3 Production expenses before net processing revenue/fees.
1
9
2,500
1,500
Commodity Price & Currency
Risk Management
STRONG FIXED PRICE NATURAL GAS RISK MANAGEMENT PROTECTION
% of total forecast 2017 gas volumes
80%
70%
$3.19
$3.33
60%
50%
40%
$3.06
$3.06
$3.06
$3.06
Q1/18
Q2/18
Q3/18
Q4/18
30%
20%
10%
0%
Q3/17
Q4/17
AECO Swap (C$/Mcf)
NATURAL GAS HEDGES
AECO fixed price swap contracts:
•
•
•
117.0 MMcf/d @ C$3.19/Mcf (Q3 2017)
102.2 MMcf/d @ C$3.33/Mcf (Q4 2017)
66.1 MMcf/d @ C$3.06/Mcf (2018)
10
PROPANE HEDGES
Conway propane swap contracts:
•
•
•
1,500 bbl/d @ 50.7% WTI (Q3-Q4 2017)
500 bbl/d @ 51.5% WTI (Q3-Q4 2017)
1,000 bbl/d @ 47.0% WTI (2018)
CURRENCY HEDGES
USD foreign exchange forward
contract summary:
•
$62.5MM @ 1.308 USD/CAD
(value date May 2020)
Percent of forecast volumes based on the mid-point of updated (August 10, 2017) 2017 average production guidance of 36,000 boe/d (76% natural gas weighted). Natural gas hedges converted
from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.3 Mj/m3.
Conway propane price referenced as a percentage of WTI in U.S. dollars.
All hedges denominated in Canadian dollars unless otherwise noted.
Highly Concentrated Land Base
DOMINANT ACREAGE POSITION
WEST CENTRAL ALBERTA CORE AREA
 Highly focused land base in
the prolific Deep Basin of
Alberta
 Control of significant
infrastructure (facilities,
pipelines, compression)
creates barriers to
competition
~100 Kilometers (60 Miles)
 99% of total corporate
production and 100% of
capital investment focused
in the Greater Ferrier,
Willesden Green & Pembina
areas of Alberta
FERRIER
WILLESDEN GREEN
GREATER PEMBINA
Alberta
~77 Kilometers (48 Miles)
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1
2
Reflects % of June 2017 average field volumes and excludes divested Strachan area which closed June 26, 2017
Proved and Probable and unbooked locations as at December 31, 2016
Production1 (% of total):
99%
P+P net locations2:
248
Unbooked net locations2:
444
Total net drilling locations:
692
Concentrated Multi-Zone Acreage
DEEP BASIN MULTI-ZONE ACREAGE
 Deep Basin is highly coveted for:
• Sweet, liquids rich natural gas
• Sweet, light gravity crude oil
• Multi-zone hydrocarbon charged
formations
• Low production cost with no formation
water
• Year round access
 Benefits of multi-zone development:
• Pad drilling reduces above ground
footprint
• Lease sizes minimized
• Manufacturing style approach
• Half-cycle returns expected longer term
as subsequent formation development
utilizes existing lease pads, pipelines,
and infrastructure
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TVD: True vertical depth
4,600 ft TVD—
6,200 ft TVD—
— Belly River
— Cardium
— Second White Specs
7,400 ft TVD—
— Viking
— Notikewin
7,700 ft TVD—
— Falher A
— Falher B
— Wilrich
— Glauconite
— Ostracod
— Ellerslie
— Rock Creek
11,200 ft TVD—
— Nordegg
— Duvernay
Spirit
River
Focused Spirit River Growth
SPIRIT RIVER PRODUCTION GROWTH
2010
30,000
Spirit
River
24,000
45%
18,000
30%
12,000
15%
6,000
Spirit River % of Total
Other
June 2017
Other
Spirit
River
May 17
Jan 17
Sep 16
May 16
Jan 16
Sep 15
May 15
Jan 15
Sep 14
May 14
Jan 14
Sep 13
May 13
Jan 13
Sep 12
May 12
Jan 12
Sep 11
May 11
Jan 11
Sep 10
0
May 10
0%
Average Monthly Production (boe/d)
60%
Jan 10
Spirit River % of Total Company Volumes
75%
Monthly Production (boe/d)
Low cost Spirit River volumes comprise a growing proportion of total corporate production (~75%)
Processing facilities and Firm Transportation (FT) capacity in place to facilitate growth
13
Spirit River - The Quiet Giant
WESTERN CANADA 2016 WELLS – CALENDAR DAY PRODUCTION BY ZONE
Spirit River
Montney
L Mannville
Viking
Bakken
Glauconitic
Cardium
Duvernay
Shaunavon
Colorado
Mississippian
Charlie Lake
0
10,000
20,000
30,000
40,000
50,000
60,000
Calendar average daily cumulative volumes (boe/d)
2016 WELL (BOE) VOLUMES BY ZONE
Other
Spirit
River
Montney
14
Spirit River accounted
for ~33% of total
Western Canada
hydrocarbon volumes
(boes) from new wells
drilled in 2016
Source: Data from Canadian Discovery Ltd.; excludes oilsands and thermal oil wells/volumes
70,000
80,000
2016 WELL (MCF) VOLUMES BY ZONE
Other
Montney
Spirit
River
Spirit River accounted
for ~50% of total
Western Canada
natural gas volumes
(Mcf) from new wells
drilled in 2016
Spirit River Geology Summary
• Broad, thick, extensive sand rich valleys in
Notikewin, Falher and Wilrich members
• Tight sandstone: long life reserves with
long term hyperbolic decline profile
• Average thickness 25 to 40 meters
(approximately 80 to 130 feet)
SPIRIT RIVER STACKED SANDS
One square
mile section
schematic
— Notikewin
• Up to three wells per zone to fully develop
a section
— Falher A
• Porosity 6 to 18%; permeability 1 to 3 mD
— Falher B
• Open and closed fracture systems evident
in rock core and to a lesser degree in rock
cuttings
15
— Wilrich
Spirit River Liquids Rich Gas
BXE Land Sections1
GREATER FERRIER AREA CORE SPIRIT RIVER PLAY
204 Gross
112 Net
BXE Net Drilling Inventory2
86 proved
30 probable
265 unbooked
381 total
•
True vertical formation depth
~2,250 meters (~7,400 feet)
•
Currently drilling one mile laterals
•
Average 17 frac stages per well
with 40 tonnes per stage
Spirit River
(Notikewin/Falher/Wilrich)
provides significant upside
16
1
2
Includes Ferrier, Willesden Green, and greater Pembina. Acreage as at June 30, 2017
Proved, Probable, and unbooked locations as at December 31, 2016 and excludes Strachan area
North American Supply Cost Comparison
$4.00
$3.50
Henry Hub (US$/MMbtu)
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
17
Economics assume 15% Before tax IRR, assumes $US0.83 = $CDN1.00, US$0.75/MMbtu AECO basis, and a 20:1 oil-to-gas pricing ratio;
Note (*): Bellatrix economics assume to be free of GORR
Source: RBC Capital Markets Research
Spirit River All-In Profitability
C$2.50/GJ
C$3.00/GJ
Full cycle F&D costs $/Mcfe
($0.85)
($0.85)
Cash costs
($2.14)
($2.18)
$/Mcfe
Sales price
$/Mcfe
$3.91
$4.42
Profit
$/Mcfe
$0.92
$1.39
Profit margin
%
24%
31%
Half Cycle IRR
%
35%
62%
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Full Cycle F&D costs
Drill
Complete
Equip & tie in
Half cycle costs
Land/seismic/facilities
Full cycle costs
$1.7MM
$1.6MM
$0.7MM
$4.0MM
$1.1MM
$5.1MM
EUR (P50)
Full cycle F&D
6.0 Bcfe
$0.85/Mcfe
Cash costs
C$2.50/GJ
C$3.00/GJ
Royalties (est @ 8%)
Operating costs 1
Transport2
G&A2
Interest & financing2
Total costs
$0.31/Mcfe
$0.75/Mcfe
$0.26/Mcfe
$0.34/Mcfe
$0.48/Mcfe
$2.14/Mcfe
$0.35/Mcfe
$0.75/Mcfe
$0.26/Mcfe
$0.34/Mcfe
$0.48/Mcfe
$2.18/Mcfe
Sales price
C$2.50/GJ
C$3.00/GJ
Total sales price3
$3.91/Mcfe
$4.42/Mcfe
Note: Numbers may not add due to rounding
1 Incremental operating costs assume $0.56/Mcf for natural gas through third party plants, $0.20/Mcf for gas processed through BXE Alder plant and $8.00/bbl for oil/condensate. Assumed split
is 80% 3rd party / 20% BXE plant. Includes estimated attributed operating cost impact from $75 million facilities disposition announced May 13, 2016.
2 Representative transport, G&A and interest costs based on average first half 2017 corporate costs
3 Sales prices assume AECO at $2.84/Mcf ($2.50/GJ) or $3.41/Mcf ($3.00/GJ) as per scenario with NGL pricing: ethane @ $10/bbl, propane @ $15/bbl, butane @ $30/bbl and condensate @
$60/bbl incorporating liquids extraction capabilities given mix of gas through third party and BXE Alder Flats Plant.
Delivering on our 2017 Objectives
2017 RESULTS OUTPERFORMING TYPE CURVE EXPECTATIONS
20
18
Producing day volumes (MMcf/d)
16
14
12
10
8
6
4
2
0
0
30
60
2017 Wells
19
90
120
150
180
Days
2017 Average
Historical daily well production (natural gas only) versus Bellatrix representative 5.2 Bcf type curve
210
240
270
300
BXE Spirit River 5.2 Bcf Type Curve
330
360
Spirit River Well Costs & Capital Efficiencies
FOCUSED CAPITAL COST REDUCTIONS
Long Reach
$6.0
$3.0
$2.0
Long Reach
$4.0
Long Reach
Costs ($millions)
$5.0
Equip & Tie-in
Complete
Drill
$1.0
$0.0
2015 - 24 wells
2016 - 19 wells
2017 - 8 wells
DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING ~$8,000/BOE/D
Capital Efficiency ($/boe/d)
20,000
Spirit River
IP365
Capital
Efficiency
($/boe/d)
Full Capital
Program
Average
15,000
10,000
5,000
0
20
2015 - 24 wells
2016 - 19 wells
2017 - 8 wells
Note: IP365 forecasts based on initial well productivity, reservoir characteristics, and full year well production modeling
Capital efficiency calculated as gross well costs (drill, complete, equip and tie-in) divided by gross IP365 production expectation of Falher B and Notikewin wells drilled
Analysis of operated wells only and does not include promoted spend within historical JV development. Two June 2017 Spirit River wells excluded from analysis due to limited time on-stream
Enduring Efficiency Gains
AVERAGE SPIRIT RIVER DRILLING CURVES
SPUD TO RIG RELEASE BY YEAR
0
Days (Spud to Rig Release)
20
2014 Spirit River Average
500
15
2015 Spirit River Average
1,000
2017 Spirit River Average
1,500
2,000
5
0
2,500
3,000
2015
2016
2017
$3.0
$2.5
3,500
4,000
4,500
5,000
0
5
10
Days Spud to Rig Release
21
2014
DRILL COST BY YEAR
Drill Cost ($MM)
Measured Depth (m)
10
2016 Spirit River Average
15
20
$2.0
$1.5
$1.0
$0.5
$0.0
2014
2015
Note: Comparative drilling curves based on one mile Bellatrix “hybrid” drilling style which constitutes technique employed for majority of wells drilled since 2014
2016
2017
Spirit River Development Comparison
COMPARATIVE 2015 & 2016 SPIRIT RIVER COST & EFFICIENCY METRICS
$5.0
BXE
15
10
5
0
Industry
BXE
Reported costs
7.0
Completion cost
Industry
IP90 Gas rate
6.0
Drill cost
$4.0
$3.0
$2.0
$1.0
$0.0
20
5.0
4.0
3.0
2.0
1.0
BXE
Industry
0.0
Proppant per stage (tonnes)
5
25
BXE
Industry
Capital efficiency ($/boepd)
10
$6.0
Number of completion days
30
Days to complete
15
0
Well costs ($ millions)
Frac stages
IP90 (MMcf/d)
Number of stages
20
70
Avg proppant placed per stage
60
50
40
30
20
10
0
7,000
BXE
IP90 Capital efficiency
6,000
5,000
4,000
3,000
2,000
1,000
0
BXE
Bellatrix is an industry leader in the development of the Spirit River play
22
Source: Canadian Discovery Frac Database. Data sourced December 2016.
Calendar data based on spud date.
Industry
Industry
Representative Spirit River Inventory
Required to Maintain Production Volumes
Approximately 14 net Spirit River wells1 per year maintains production
in the mid 30 mboe/d range through 2020
Represents scenario of drilling of only 15% of net Spirit River well inventory
40
Production (mboe/d)
30
20
10
0
Jan-17
Jul-17
Base
Jan-18
Beginning net location inventory
Net locations drilled
Ending net location inventory
% drilled of total inventory
23
2017
Jul-18
2017
381
14
367
4%
Jan-19
2018
2018
367
14
353
4%
Jul-19
2019
353
14
339
4%
2019
Jan-20
2020
339
14
325
4%
Jul-20
2020
Total
381
56
325
15%
Assumes phased drilling development with average well results in line with Bellatrix Spirit River type curve. Representative example only as future budgets, drill plans ,and anticipated well
results are uncertain
Cardium Light Oil Resource Play
BXE Land Sections1
155 Gross
99 Net
BXE Net Drilling Inventory2
92 proved
29 probable
85 unbooked
206 total
Cardium Resource Play Summary
Largest accumulation of light oil in the
WCSB
Approximately 20,000 square miles
Approximately 1.9 Billion bbls produced
to date
Cardium provides light oil exposure with
material optionality to improving prices
Remains a key focus formation for
Bellatrix long-term within its core areas
24
1
2
Acreage as at June 30, 2017
Proved, Probable, and unbooked locations as at December 31, 2016, numbers exclude Strachan area
Conventional (vertical) Cardium development
Expanded (horizontal) Cardium development
Cardium wells
Strategic Land Position
GREATER FERRIER/BRAZEAU/WILLESDEN GREEN AREAS OF WEST CENTRAL ALBERTA
Pembina
Brazeau
Ferrier
Willesden Green
25
Bellatrix
Peyto
TAQA
Cenovus
Tourmaline
Westbrick
Source: Accumap, company presentations and various public sources
Greater Ferrier Area Infrastructure Overview
GREATER FERRIER EXISTING
INFRASTRUCTURE ACCESS:
Infrastructure gives Bellatrix control
of production and growth
Working interest or operatorship in
3 major gas processing facilities
9 compressor sites
4 oil batteries
BELLATRIX ALDER FLATS PLANT
Bellatrix 25% owner and operator
• Keyera 70% owner
• O’Chiese 5% owner
Phase I - 110 MMcf/d inlet capacity
(on-stream May 2015)
Phase II - 120 MMcf/d inlet capacity
(in service 2018, remaining BXE cost
plus prepayment capital ~$25MM)
•
C2 Recovery 57%
•
C3 Recovery 99%
•
C4+ Recovery 100%
Strategic advantage from
owned infrastructure –
lowered costs and
guaranteed access
26
GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE
Drill Bit Focused
PLANT INVESTMENT & CONSTRUCTION COMPLETE Q2/18
Major compressor stations, pipelines and Bellatrix Alder Flats Plant capital investment nearing completion
Proportion of incremental capital to drilling & completion expected to increase
Increased drill bit directed capital positions Bellatrix to deliver enhanced corporate capital efficiency
rates in 2018 & 2019
Plant
Plant
20%
10%
0%
2014
2015
2016
DRILLING
DRILLING
30%
DRILLING
60%
40%
Plant
Plant
70%
50%
Plant
Land, G&G, and other capital
80%
DRILLING
% of Total E&D Capital Expenditures
90%
ALLOCATION OF TOTAL CORPORATE E&D CAPITAL EXPENDITURES
DRILLING
100%
DRILLING
•
•
•
BXE Alder Flats Plant
Facilities & equipment
(excluding BXE Plant)
Drilling & completion capital
2017E
2018E
2019E
Drilling and completion capital includes capitalized items
Note: Capital expenditures and development plans beyond 2017 represent management estimates, as formal plans have not been approved. For representation purposes 2018 & 2019
1
27 capital investment levels assume similar capital spending levels as 2017 for each category, with assumed completion of Phase 2 of the Bellatrix Alder Flats Plant in H1/2018.
1
BXE Alder Flats – Superior Operational
Performance in Core West Central AB Area
SUPERIOR & CONSISTENT PLANT PERFORMANCE
Highest
Utilization
Bellatrix Alder Flats
Bellatrix Alder Flats
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
3rd Party Plant
0%
20%
40%
60%
80%
January 2016 to June 2017 utilization (%)
100%
BXE Alder Flats has averaged a 97% utilization rate
since July 1, 2015
28
FUEL/DISPOSITION EFFICIENCY
Most efficient
0.0%
2.0%
4.0%
January 2016 to June 2017 Disposition % of Receipts
BXE Alder Flats ranks best in group
as the most efficient plant
Source: Bellatrix internal data and Alberta Energy Regulator (AER)
Note plant efficiency compares monthly receipts versus licensed gas capacity for third party plants. BXE Alder compares monthly gas receipts versus sales capacity
Note: Fuel disposition efficiency includes fuel, flared and vented dispositions as a % of input plant receipts
Third party plants include greater Ferrier area gas plants: Tidewater Brazeau River Complex, Conoco Sand Creek, Conoco Alder Flats, Keyera Minnehik Buck Lake, Keyera Nordegg, Keyera
Brazeau East, Keyera West Pembina, Keyera Brazeau North, Obsidian Crimson Lake
Ample Takeaway Capacity & Market Egress
AMPLE FIRM TRANSPORTATION IN PLACE FOR
CURRENT & GROWTH VOLUMES
• Firm Transportation (FT) agreements in place
representing ~120% of current gross operated volumes
at multiple receipt points along the Nova Gas
Transmission Ltd. (NGTL) system
• Additional FT capacity secured upon completion of
Phase 2 of Alder Flats Plant to facilitate increased
forecast growth volumes
ALBERTA NATURAL GAS MARKET EGRESS
ALBERTA
Montney
FIRM SERVICE PROCESSING CAPACITY
• Maintain firm service capacity through several natural
gas processing plants to ensure unfettered delivery
capability for current & forecast growth volumes
• Multiple staggered third party processing contract
maturities to align with anticipated in-service date of
Phase 2 of Alder Flats Plant
AMPLE FRACTIONATION CAPACITY SECURED
• Long term agreements in place provide 100% coverage
for current and forecast NGL volume growth
29
Alliance Pipeline
BXE core west central
area ideally situated on
the NGTL system,
downstream of Montney
& northern Deep Basin
areas, with ~120% firm
transportation capacity
Nova Gas
Transmission
Ltd. (NGTL)
System Pipelines
Compelling Investment Opportunity
 SUSTAINABILITY
Excellent Organic
Growth Potential
Competitive
Economics
 PROFITABILITY
 LONG TERM GROWTH
De-risked
Leading Well
Results
Technically
Astute
30
Corporate Information
BOARD OF DIRECTORS
W.C. (Mickey) Dunn
Chairman
Murray L. Cobbe
SENIOR OFFICERS
Brent A. Eshleman, P.Eng.
President & CEO
Max Lof, CFA
Executive Vice President & CFO
John H. Cuthbertson, QC
Brent A. Eshleman, P.Eng
Charles R. Kraus, Esq.
Executive Vice President, General
Counsel & Corporate Secretary
Lynn Kis, P.Eng
Keith E. Macdonald, CPA, CA
Thomas E. MacInnis, B.Comm, MBA
Garrett Ulmer, P.Eng
Chief Operating Officer
Steve G. Toth, CFA
Vice President, Investor Relations
Steven J. Pully, CPA, CFA
Murray B. Todd, B.Sc., P.Eng.
ADDRESS
1920, 800 – 5th Avenue SW
Calgary, Alberta Canada T2P 3T6
Keith S. Turnbull, B.Sc., CPA, CA
Tel: (403) 266-8670
Fax: (403) 264-8163
www.bellatrixexploration.com
[email protected]
31
BANKERS
National Bank of Canada
Alberta Treasury Branches
The Bank of Nova Scotia
Canadian Western Bank
EVALUATION ENGINEERS
InSite Petroleum Consultants Ltd.
REGISTRAR & TRANSFER AGENT
Computershare Trust Company of Canada
AUDITORS
KPMG LLP
EXCHANGE LISTING
The Toronto Stock Exchange - BXE
The New York Stock Exchange – BXE
RATING AGENCIES
Moody’s Investor Service Inc.
Corporate Rating: B3
Senior Notes Rating: Caa1
Standard and Poor’s Rating Service
Corporate Rating: B
Senior Notes Rating: B
bellatrixexploration.com