Download SOAH DOCKET NO. 473-00-1328 PUC DOCKET NO. 22532

SOAH DOCKET NO. 473-00-1328
PUC DOCKET NO. 22532
APPLICATION OF CITY PUBLIC
SERVICE OF SAN ANTONIO FOR
APPROVAL OF NON-IOU
TRANSMISSION COST OF SERVICE
FILING
§ PUBLIC UTILITY COMMISSION
§
§
OF
§
§
TEXAS
RESPONSE OF SAN ANTONIO CITY PUBLIC SERVICE BOARD
TO ORDER REQUESTING ADDITIONAL INFORMATION AND CLARIFICATION
TO THE HONORABLE PUBLIC UTILITY COMMISSION:
The San Antonio City Public Service Board (“San Antonio”) provides the following
response to the order issued on December 15, 2000:
1.
A comparison of rate base and revenue requirement between the last approved
TCOS and the request as filed/settled. For each item, provide a short explanation of
any change in the number.
See Exhibit 1.
The major factor contributing to the difference between the revenue requirements
approved by the Commission in San Antonio’s last TCOS case and the current settled TCOS
case is San Antonio’s use of the cash flow method in the determination of the appropriate
revenue requirement for a municipal utility. The use of the cash flow method is consistent with
the Non-IOU Rate Filing Package requirements (Schedule C-2) approved by the Commission in
December 1999. The cash flow method allows a more accurate determination of municipal
utility revenue requirements, including construction funded from cash and city general fund
transfer payment at bond ordinance/indenture-approved levels, than does the debt service
coverage method.
2.
Transmission rate base additions (other than generation interconnection projects
listed below). Include a project-specific summary stating construction start date,
the docket/filing approving the transmission project (if applicable), the in-service
date, a facility description (mileage, voltage, end-points, substation, etc. ) and the
dollar impact on both rate base and revenue requirement.
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Exhibit 2 is a summary of major transmission additions (projects greater than $10,000)
with the requested information provided. The dollar impact on rate base due to transmission
additions is shown on Exhibit 2 in the column headed Total Cost. The total change in rate base
from the 1995 test year to the 1999 test year (as shown on Exhibit 1) is the result of net additions
to plant for improvements to existing facilities and for system expansion and standard
depreciation and retirement unit accounting entries. The total change to transmission rate base
from 1995 to 1999 also includes an allocation of the distribution substation facilities that are
defined as transmission per PUC Rule 25.192(b). A summary of transmission plant additions
and retirements, the impact of reclassification of costs between generation, transmission and
distribution, and the allocation of general and common plant to transmission is shown at the
bottom of page 7 of Exhibit 2.
San Antonio’s revenue requirements are set using the cash flow method described in
Schedule C-2 of the Non-IOU Rate Filing Package, not the rate of return method. Rate Base is
used for allocating debt service costs to generation, transmission and distribution. Therefore,
changes in rate base affect the transmission revenue requirement only to the extent they affect
the percentage of total debt service that is allocated to the transmission function. The effect of
rate base on the allocation of debt service costs to transmission is shown on Exhibit 1 in the row
referring to Return (Debt Service). For the 1999 test year period (October 1998 – September
1999), $16.8 M (or 7.4% of the total debt service assigned to the electric system) was allocated
to the transmission function.
Note that because rate base and depreciation expense do not enter into the determination
of revenue requirements, the time between in-service dates and closed-to-plant dates for the
projects shown in this exhibit does not affect transmission cost of service. For some projects, an
accurate In-Service date was not available; however, a Closed-to-Plant date was provided for all
projects. No project is closed to plant until it is in service.
3.
New generation interconnection projects. Specify the generation plant being
interconnected and the line construction start date, the in-service date, the voltage,
and the dollar impact on rate base and revenue requirement.
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During the October 1998 to September 1999 test year, San Antonio was in the process of
constructing transmission lines and the switching station to interconnect the Arthur von
Rosenberg power plant. Details related to this project are set out in Exhibit 3.
4.
Given that many transmission functions have been transferred over the years to
ERCOT and that ERCOT is moving to a single control area, what is the justification
for recovering some of the control area costs through TCOS in the future?
The establishment of a single control area for ERCOT has little effect on the
responsibilities of the local transmission and distribution service provider (TDSP). The TDSP
will continue to be responsible for providing most of the information required by ERCOT for
single control area operations. In the past, the transmission control function provided the
necessary data, but it was the generation control function that actually balanced supply and
demand in the control area. It is the latter functionality that is moving to ERCOT (i.e., ERCOT
will perform the calculations and issue the instructions to balance supply and demand, and the
generators will respond).
The TDSP will also take on new responsibilities. For example, the protocols place the
responsibility for generation and load metering, and the operation and maintenance related to that
equipment, solely with the TDSP. The TDSP will also retain responsibility for monitoring,
controlling, switching and maintaining all transmission lines and substations within its service
territory. The TDSP retains responsibility for transmission reliability that requires constant
monitoring and control of lines, breakers, relays, transformers and related substation equipment.
The establishment of the single control area operation simply means that ERCOT rather
than the TDSP will provide the instructions for action. The local TDSP will continue to be the
entity that performs the action, except for generation control activities. No significant change in
operational activity occurs with the TDSP as a result of ERCOT becoming a single control area.
San Antonio has included in its TCOS only the transmission-related control area costs it
incurred in its historical test year (1999) and has included only costs allowed under the existing
transmission rules. Note that San Antonio filed a historic test year and included only actual costs
incurred for system control. San Antonio did not forecast expenses.
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5.
Do any of the non-transmission costs being included in TCOS violate the
Commission’s final order in Docket No. 15840?
No. San Antonio did not include any costs in its TCOS that are in violation of the
Commission’s final order in Docket No. 15840.
6.
Provide a complete definition of the terms “bond defeasance” and “cash
defeasance” and provide examples. Explain the relationship between debt service, cash
available for construction, and depreciation as reported by non-municipal [sic] utilities.
Explain how net transmission plant in service increases with new plant additions and
decreases with plant depreciation (or the municipal accounting alternative) Provide
examples.
Defeasance 1 – A financial transaction resulting in the termination of the rights and interests of
the bondholders and of their lien on the pledged revenues in accordance with the terms of the
bond contract for an issue of securities.
Cash Defeasance 2 – The defeasance of debt resulting from a transaction in which accumulated
cash funds are used to immediately retire debt or are placed in escrow to meet the debt service
requirements of the defeased bonds.
Bond Defeasance 2– The defeasance of debt commonly associated with an advance refunding or
refunding transaction. Refunding occurs when an issuer refinances an outstanding bond issue by
issuing new bonds. In an advance refunding the resulting proceeds of the new issue are deposited
in escrow to pay the debt service on the original outstanding issue when due. In the case of a
refunding the proceeds are immediately used to retire the original outstanding obligation. This is
essentially the same type transaction for a cash defeasance, except a new bond issue is involved.
See Exhibit 4 for examples of these transactions.
San Antonio assumes that the purpose of this question is to draw a correlation between
the setting of revenue requirements for non-municipal utilities and municipally owned utilities.
In the determination of revenue requirements, an investor-owned utility (IOU) includes
Adopted from the Dictionary of Finance and Investment Terms, Fourth Edition, (Barron’s Educational Series Inc.
1995)
2
Adopted from the Glossary of Municipal Securities Terms, (Municipal Securities Rulemaking Board, 1985)
1
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depreciation expense in its cost of service whereas debt service and cash required for
construction are not included. These elements of an IOU’s cash flows are provided by the return
on rate base that is included in the IOU’s revenue requirements. Many municipal utilities
including San Antonio use the cash flow method to determine their revenue requirements. Under
this method, total annual debt service and cash required for construction are included in revenue
requirements and depreciation expense is not included. No element of the municipal utility cost
of service equates to the IOU’s return on rate base.
Plant and depreciation accounting is substantially the same for investor-owned and
municipally owned utilities. Under FERC accounting rules, recorded utility plant is subdivided
into units of property, sometimes called retirement units. Transmission plant in service increases
when new plant additions are recorded. However, the retirement of a unit of property does not
increase or decrease net plant in service. The depreciation reserve account is debited in exactly
the same amount as the credit to utility plant in service for the original cost of the property unit
retired. Cost of removal, less any salvage value of the retired plant is also charged to the
depreciation reserve account.
Net plant in service is reduced by the amount of depreciation expense recorded in an
accounting period. Depreciation rates are established based upon remaining life studies and are
periodically adjusted to make up for any deficiencies in the reserve for deprecation caused by
premature retirements.
Numerical example:
Assume the following on 12/31/00: Transmission Plant in Service is comprised of
$1,000 in plant, and the balance of accumulated depreciation is $400. During year 2001, $200
dollars in transmission plant is placed in service and $100 is retired. Also, transmission
depreciation expense for the period is $50. The effect on Net Transmission plant would be the
following:
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Balance Sheet Changes
Balance Sheet at
At 12/31/2000 During 2001 12/31/2001
Assets
Beginning Transmission Plant In Service
Plus additions to plant in service
Less retirements
Transmission plant in service
Less Accumulated Depreciation
Depreciation expense
Plant retired
Subtotal Accumulated Depreciation
Net Transmission Plant in Service
1,000
0
- 0
1,000
0
200
-100
100
1,000
200
- 100
1,100
- 400
600
-50
100
50
150
- 350
750
7.
What is the debt amortization period for the new transmission projects and for the
existing projects already included in the CPS asset base? What is the assumed asset life for
these projects?
There is no debt associated with new transmission projects occurring in San Antonio’s
test year. All new transmission projects occurring in San Antonio’s test year were funded with
internally generated cash due in part to IRS private use restrictions on the use of tax exempt debt
for transmission facilities. The negotiated settlement does not specify a debt amortization period
for new transmission projects.
Prior to the issuance of 1998 U.S. Treasury Department regulations interpreting IRS
private use restrictions1 and the implementation of open access transmission in Texas, San
Antonio did not track bond issues by capital project or by business function. San Antonio’s
historical practice has been to issue bonds based upon the capital requirements of the integrated
utility. This practice makes it impossible to establish a correlation between debt amortization on
a non-asset specific basis with specific assets or plant accounts. The remaining debt amortization
period for existing electric transmission related assets in San Antonio’s transmission cost of
service filing is 30 years inclusive of commercial paper debt service. The corresponding
estimated average remaining asset life for transmission-related assets is 27 years. The current
1
The Treasury Department regulations which became effective in 1998 grandfathered the status of bonds issued
prior to July 9, 1996 to fund transmission facilities that might have private business use related to open access
mandates. U.S. Treasury Regulations Section 1.141-7T. The import of the regulations is that the tax-exempt status
of bonds issued after that date is not protected to the extent used to fund open access transmission facilities.
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negotiated settlement does not specify a debt amortization period for existing transmission
projects.
Respectfully submitted,
MATTHEWS AND BRANSCOMB
A Professional Corporation
112 East Pecan Street
Suite 1100
San Antonio, Texas 78205
(210) 357-9300
(210) 357-9324 (Facsimile)
W. Roger Wilson
State Bar No. 21733500
Paul M. Gonzalez
State Bar No. 00796652
___________________________
W. Roger Wilson
CERTIFICATE OF SERVICE
I hereby certify that a true and correct copy of the foregoing document was served this
2nd day of January, 2001, upon all parties of record by facsimile or by deposit in the U.S. mail,
postage prepaid.
______________________________
W. Roger Wilson
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