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1 STATE OF ALASKA
2 THE REGULATORY COMMISSION OF ALASKA
3
Before Commissioners: Dave Harbour, Chair
4 Will Abbott
Mark K. Johnson
5 James S. Strandberg
G. Nanette Thompson
6
7 In the Matter of the Investigation into the )
Agreement for Sale by SHELL WESTERN E&P, ) U-96-36
8 INC. and SHELL ONSHORE VENTURES, INC., )
of Their One-Third Working Interest in the ) ORDER NO. 33
9 Beluga River Gas Field and the Purchase )
Thereof by the MUNICIPALITY OF )
10 ANCHORAGE d/b/a MUNICIPAL LIGHT & )
POWER DEPARTMENT and Tariff Revisions )
11 Designated as TA261-121, TA263-121 and )
TA264-121 filed by the MUNICIPALITY OF )
12 ANCHORAGE d/b/a MUNICIPAL LIGHT & )
POWER DEPARTMENT for the Quarterly )
13 Revision of Its Cost of Power Adjustment )
Surcharge )
14
ORDER SUSPENDING TA264-121; APPROVING INTERIM AND REFUNDABLE
15
COPA RATE; APPROVING NONFIRM PURCHASED POWER RATE; AND
16 APPROVING TARIFF SHEETS
(907) 276-6222; TTY (907) 276-4533
Regulatory Commission of Alaska
17
701 West Eighth Avenue, Suite 300
BY THE COMMISSION:
Anchorage, Alaska 99501
18
Date Filed: February 14, 2003 End of 45 Day Period: March 31, 2003
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1. The Commission should suspend TA264-121 for a period
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coterminous with the existing suspension period of TA261-121 and TA263-121
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pending resolution of rate design issues in U-96-36 that affect the gas transfer price
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used in ML&P’s COPA filings.
23
2. The Commission should approve, on an interim and refundable basis,
24
a COPA rate of ($.00897)/kWh, effective April 1, 2003.
25
26
U-96-36 (33) - (03/17/03)
Page 1 of 2
1 3. The Commission should approve a Nonfirm Purchased Power rate of
2 $.02206/kWh, effective April 1, 2003.
3 4. The Commission should approve Tariff Sheet Nos. 101.3, 101.6.1
4 and 121, filed by Municipal Light & Power (ML&P) on February 14, 2003, effective
5 April 1, 2003. Side-by-sides of the tariff sheets are attached as WA-1.
6 5. The Commission should amend the title of Docket U-96-36 to include
7 TA264-121.
8 Reasons for the above indicated recommendation: Memo Attached
9 Order
10
THE COMMISSION FURTHER ORDERS:
11
For good cause shown in the attached Staff memorandum, the Commission accepts
the recommendations set out above. The Commission hereby suspends the
12 permanent operation of this Tariff Advice for a period coterminous with the existing
suspension period of TA261-121 and TA263-121 in this docket.
13
Commission decision re this order:
14 Date (if I CONCUR I DO NOT I WILL
different CONCUR WRITE A
15
from DISSENTING
16
3/14/03) STATEMENT
Harbour /S/
(907) 276-6222; TTY (907) 276-4533
Regulatory Commission of Alaska
17
701 West Eighth Avenue, Suite 300
Abbott /S/
Anchorage, Alaska 99501
18 Johnson /S/
19 Strandberg /S/
20 Thompson /S/
21
22
23
24 (SEAL)
25
26
U-96-36 (33) - (03/17/03)
Page 2 of 2
1
2 MEMORANDUM
3 To: G. Nanette Thompson, Chair Date: March 10, 2003
Bernie Smith
4 Dave Harbour File: TA264-121
Will Abbott
5 James S. Strandberg
6
From: Wendy Arnett Subject: COPA; NFPPR
7 Utility Tariff Analyst
8
RECOMMENDATION
9
1. The Commission should suspend TA264-121 for a period
10
coterminous with the existing suspension period of TA261-121 and TA263-121
11
pending resolution of rate design issues in U-96-36 which affect the gas transfer price
12
used in ML&P’s COPA filings.
13
2. The Commission should approve, on an interim and refundable basis,
14
a COPA rate of ($.00897)/kWh, effective April 1, 2003.
15
3. The Commission should approve a Nonfirm Purchased Power rate of
16
$.02206/kWh, effective April 1, 2003.
17
4. The Commission should approve Tariff Sheet Nos. 101.3, 101.6.1
18
and 121, filed by Municipal Light & Power (ML&P) on February 14, 2003, effective
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April 1, 2003. Side-by-sides of the tariff sheets are attached as WA-1.
20
5. The Commission should amend the title of Docket U-96-36 to include
21
TA264-121.
22
23 Background
24 The following summary of issues is an excerpt from the staff memoranda for TA261-
121 and TA263-121, ML&P’s 4th quarter 2002 and 1st Quarter 2003 COPA filings:
25
26
U-96-36(33)
Appendix
Page 1 of 6
1 On July 30, 2002, the Commission issued Order No. 26 in U-96-361. In this
order, the Commission required ML&P to recalculate the gas fund revenue
2 requirement using a Debt Service Coverage (DSC) methodology. The
Commission also required ML&P to calculate all future COPA filings using the
3 DSC methodology. In the same Order, the Commission deferred its decision on
rate design issues until after ML&P filed its recalculated gas fund revenue
4 requirement.
5 Prior to U-96-36(26), ML&P used, on a conditional basis, the rate design
originally proposed in TA220-121 and U-96-36. ML&P calculated the proposed
6 gas fund revenue requirement using a rate of return/rate base methodology.
Instead of using a gas price in its COPA filings that was based on the gas fund
7 revenue requirement, ML&P used a gas transfer price of $1.50 + applicable
taxes. The difference between the gas fund net revenue requirement and the
8 revenue recovered through the COPA (with the artificial transfer price of gas)
determined the balance of the “gas cost deferral” account. ML&P proposed to
9 recover these deferred gas costs from future rate payers.
10 How the Gas Transfer Price is used in the COPA filings
11 The ML&P COPA filings consists of two main parts, calculation of the new
COPA amount (for 1st Quarter 2003 in the current filing) and the matching, in
12 the balancing account, of actual costs and actual revenues for the prior period
(3rd Quarter 2002).
13
Calculation of the new COPA amount involves estimating kWh sales, the cost
14 of gas and the cost of purchased power for the upcoming quarter. ML&P’s
estimates of gas costs comprise a large portion of total estimated costs and the
15 COPA calculation cannot be completed without some estimate of these costs.
Since ML&P’s purchase of the one-third interest in the Beluga Gas Field, it has
16 used its proposed transfer price of gas ($1.50 + taxes) in deriving its estimated
gas costs for the COPA calculation.2 The transfer price is used instead of the
17 contract price that ML&P actually pays for gas purchases from the Beluga
producers (Phillips, Chevron, ML&P). In deriving estimated gas costs, ML&P
18 applies the proposed transfer price to all volumes purchased from the Beluga
field, not just to volumes purchased from the ML&P share.
19
The second part of the COPA filing involves matching, in the balancing
20 account, revenues for a given quarter with the actual costs for that quarter. Any
over or under recovery is shown in the balancing account balance, which is
21
1
22 In the Matter of the Investigation into the Agreement for Sale by SHELL WESTERN
E&P, INC. and SHELL ONSHORE VENTURES, INC., of Their One-Third Working Interest in
23 the Beluga River Gas Field and the Purchase Thereof by the MUNICIPALITY OF
ANCHORAGE d/b/a MUNICIPAL LIGHT & POWER DEPARTMENT
24 2
In ML&P’s original rate design proposal, filed as a supplement to TA220-121, the gas
25 transfer price was to be increased by 2% per year after 2001. Accordingly, the gas transfer
price used in 2002 was $1.53 + applicable taxes.
26
U-96-36(33)
Appendix
Page 2 of 6
1 then added to the projected costs used to calculate the new COPA rate.
Subsequent to its purchase of an interest in the Beluga Gas Field, ML&P began
2 calculating “actual” gas costs entered into the balancing account using the
proposed transfer price of gas ($1.50 + taxes) instead of the actual invoice
3 price of gas for purchases from the Beluga Field. In its COPA filings, ML&P
provides a journal entry for an Interfund Transfer from its Electric Division to its
4 Gas Division as documentation for gas purchases. Again, the transfer price is
used to calculate the cost of all gas volumes purchased from the Beluga
5 purchasers, not just to the ML&P share.
6 Once again, the revenues collected through the COPA are compared to the Net
Gas Fund Revenue Requirement to derive the balance in the Deferred Gas
7 Cost account. A comparison of the actual gas contract prices (from Chevron
and Phillips invoices), the revenue requirement price (DSC method3), and the
8 gas transfer price used in the ML&P COPAs is shown in the table below.
9 TABLE 1 COPA Transfer Actual Contract Net DSC Revenue
Price (includes Price Requirement
10 Date
taxes) Price*
Actual 1997 ($/MCF) 1.60 Not filed 1.46
11 Actual 1998 ($/MCF) 1.60 Not filed 1.42
Actual 1999 ($/MCF) 1.58 1.3198 1.51
12 Actual 2000 ($/MCF) 1.59 1.5576 1.72
Actual 2001 ($/MCF) 1.64 1.8499 1.58
13 Pro forma 2002 ($/MCF) 1.68 2.3770 2.45
*Based on the recalculated DSC revenue requirement filed into U-96-36 on 8/29/02.
14
On September 30, 2002, ML&P filed for partial reconsideration of Orders 25 & 26
15
in U-96-36. In U-96-36(30), the Commission granted partial reconsideration of
ML&P’s petition. The Commission granted reconsideration of the debt service
16
coverage ratio set in Order 25. The debt service coverage ratio directly affects
the gas fund revenue requirement calculation used to determine the transfer
17
price of gas in the COPA. The quarterly COPA filings must therefore include an
estimated transfer price until this issue is resolved.
18
In its 4th Quarter 2002 and 1st Quarter 2003 COPA filings, ML&P stated it was
19
unable to determine a transfer price of gas until the rate design issues in U-96-36
were resolved. The Commission suspended these filings and approved the
20
proposed COPA rates on an interim and refundable basis (U-96-36(28) and U-
96-36(31)).
21
Discussion
22
Current Filing – 2nd Quarter 2003 COPA
23
24 3
The DSC calculation filed on 8/29/02 includes all volumes of gas purchased
25
from Beluga producers so the gas prices shown would be applied to all volumes
purchased.
26
U-96-36(33)
Appendix
Page 3 of 6
1 In the tariff advice letter to TA263-121, ML&P’s 1st Quarter 2003 COPA revision,
ML&P stated,
2
In Orders No U-96-36(25) and U-96-36(26) the Commission ordered ML&P to
3 change the method by which it determines its cost of gas for COPA filings.
However, as ML&P explained in TA261-121, some issues remain unresolved
4 and ML&P has petitioned for reconsideration of these orders, . . . .ML&P will
therefore continue to calculate its gas price for the purposes of setting COPA
5 in the same manner until ordered otherwise. For 2003, ML&P will use a
before tax gas price of $1.561/Mcf ($1.53 escalated by 2%).
6
ML&P follows this same methodology in the current filing, TA264-121, its 2nd Quarter
7 2003 COPA revision. Staff reviewed the documentation submitted by ML&P to verify
entries to the COPA balancing account. (The gas costs entered into the balancing
8 account in this filing are for the 4th quarter of 2002 and are derived using a transfer
price of $1.53 + taxes). ML&P also submitted estimates of kWh sales and costs to be
9 used in calculating the COPA rate for the 2nd quarter of 2003. (A gas price of
$1.561/Mcf is used in estimating costs for the 2nd Quarter of 2003). The effect of the
10 proposed COPA rate on an average customer billing is shown in the table below.
11 The COPA rate proposed in this filing is ($.00897)/kWh. This surcharge will decrease
an average customer billing for 550 kWh by $2.35.
12
Residential Customer Billing ML&P
13 Current CHANGE
for 550 kWh Proposed
14 COPA ($/kWh) (.00469) (.00897) .00152
Customer Charge ($) 6.56 6.56 0.00
15 Energy @ $.08803/kWh 48.42 48.42 0.00
RCC @ $.000318/kWh .17 .17 0.00
16
Surcharge (2.58) (4.93) (2.35)
Total billing 52.57 50.22 ($2.35)
17
18
Bradley Lake Hydroelectric Power and Economy Energy Sales
19 The reduction in the surcharge proposed in the current filing is due to greater than
expected energy purchases from Bradley Lake and economy energy margins. ML&P
20 projected purchases of 21,000 MWh from Bradley Lake for the 4th quarter of 2002.
Actual purchases for the period were 43,700 MWh. Increased purchases from Bradley
21 Lake result in less gas use for retail power production and reduces costs for the
quarter.
22
For the 4th Quarter of 2002, ML&P predicted economy margins of $60,000. The
23 actual margins for the period were $398,709. The economy energy margins are
credited to the balancing account and force the balance downward.
24
The cost of the gas used in generating economy energy is removed from the balancing
25 account and the COPA calculation. ML&P uses the estimated gas price of $1.561 per
Mcf in calculating the cost of economy gas. The estimated gas price is also used in
26 the calculation of economy energy margins.
U-96-36(33)
Appendix
Page 4 of 6
1 Proposed Adjustments to Balancing Account
In this filing, ML&P proposes adjustments to the balancing account for past true ups of
2 Eklutna power costs. ML&P makes monthly payments to the Eklutna Power Project
(monthly payment amount for this year is $28,632.21). Each quarter, the actual costs
3 for the project are reconciled to the payments that have been made and each owner
utility is issued a credit or a further billing to true up the Eklutna account. ML&P had
4 disputed some costs, totaling $3297.26, from 2000 and 2001 and withheld that portion
of its true-up payments. The disputed amounts were finally resolved in July, 2002.
5 ML&P included the credits it received from Eklutna in the July balancing account
entries (filed with TA263-121 for the 1st quarter of 2003). Staff determined in that filing
6 that the credits had already been accounted for in the balancing account back in 2001
when the true ups were originally calculated. As agreed, ML&P reversed the credit
7 entry of $3297.26 from its balancing account in the current 2nd quarter 2003 filing.
8 Docket U-99-139
In U-99-1394, the Commission approved a Stipulation between ML&P and PAS
9 regarding the ML&P revenue requirement. As a part of this agreement, ML&P will be
filing a revised COPA base rate calculation and moving cost recovery of Eklutna and
10 fixed gas transportation expense from the COPA to base rates. These revisions are
due to be filed in July for implementation in October 2003.
11
Gas Fund Deferral Account
12 By using an estimated transfer price of gas in the current filing, ML&P proposes to
continue deferring recovery of gas costs to future ratepayers. According to the gas
13 fund revenue requirement filing made by ML&P on August 29, 2002, the gas deferral
account was roughly $3.6 million at the end of 2002.5 The actual amount of the
14 deferral account is dependent upon the resolution of rate design issues in U-96-36.
15 The rate design issues under consideration in U-96-36 include the deferred recovery
of gas costs and the creation of an “Accumulated Deferred Asset.” The Commission
16 has not approved this accounting treatment and to date has not seen a calculation of
the Gas Fund Revenue Requirement without this treatment included. Also, in its
17 COPA filings and in the calculation of the Gas Fund Revenue Requirement, ML&P
applies its estimated gas price to all volumes of gas purchased from the Beluga Field,
18 not just the volumes purchased from ML&P. The Commission has not addressed this
specific treatment of gas costs.
19
Approval of the currently proposed COPA rate on an interim and refundable basis is
20 consistent with the Commission’s treatment of the two prior quarterly COPA filings
(TA261-121 and TA263-121). While the Commission considers the rate design issues
21 in U-96-36, ML&P must continue to recover its gas and purchased power costs. Some
22 4
See Order No.17, issued January 22, 2003, In the Matter of the Revenue
23
Requirement, Cost-of-Service, and Equity Management Plan Studies and Request for Rate
Relief Designated as TA260-121, and Tariff Revision Filings Designated as TA240-121,
24
TA243-121, and TA245-121, Filed by the MUNICIPALITY OF ANCHORAGE d/b/a
MUNICIPAL LIGHT & POWER DEPARTMENT
5
25 See Notice of Filing of Recalculated Accumulated Deferral Balance filed into Docket
No. U-96-36 on August 29, 2002.
26
U-96-36(33)
Appendix
Page 5 of 6
1 interim gas transfer price must be established for use in the COPA filings. Suspension
of TA264-121 allows the Commission to require adjustments to the 2nd Quarter 2003
2 COPA calculation that will be consistent with the final decision regarding rate design
issues in U-96-36.
3
NFPPR
4 The NFPPR proposed in this filing is $.02206/kWh. The rate was calculated
accurately in accordance with the Commission approved methodology. Staff
5 recommends the Commission approve the NFPPR effective April 1, 2003.
6 Conclusion
Staff recommends the Commission suspend TA264-121 pending the resolution of rate
7 design issues under consideration in U-96-36. The Commission should approve the
proposed COPA rate of ($.00897) per kWh on an interim and refundable basis.
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U-96-36(33)
Appendix
Page 6 of 6
PAGES WA-1 THROUGH WA-3 REFERENCED
IN THE TEXT OF THIS DOCUMENT ARE
AVAILABLE ON OUR LIBERTY SYSTEM
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