20031027Decision Memo.pdf

DECISION MEMORANDUM
TO:COMMISSIONER KJELLANDER
CO MMISSI 0 NER SMITH
CO MMISSI 0 NER HANSEN
COMMISSION SECRETARY
COMMISSION STAFF
LEGAL
FROM:SCOTT WOODBURY
DATE:OCTOBER 23, 2003
RE:CASE NO. A VU-03-06 (A vista)
CONTINUATION OF POWER COST ADJUSTMENT (PCA) SURCHARGE
On August 11 , 2003, Avista Corporation dba Avista Utilities (Avista; Company)
filed a Power Cost Adjustment (PCA) Schedule 66 Status Report with the Idaho Public Utilities
Commission (Commission) and an Application requesting approved recovery of excess power
costs deferred through June 30, 2003 and further continuation of a 19.4% ($23.6 million) PCA
surcharge currently scheduled to expire on October 11 , 2003. Following a public hearing, the
19.4% surcharge was originally authorized by the Commission in Order No. 28876 dated
October 11 , 2001 in Case No. A VU-01-11. A 12-month continuation of the surcharge was
authorized following a public workshop and comments in Order No. 29130 in Case No. A VU-
02-6. In its Order continuing the surcharge, the Commission stated:
As we did last year, we find it reasonable to continue a close monitoring of
the Company s PCA decisions and thus require the Company to file a PCA
status report 60 days prior to the expiration of the PCA surcharge. As before
if the status report and our review of the actual PCA deferral balance supports
continuation of the surcharge, we anticipate continuation of the surcharge for
an additional term.
Order No. 29130, p. 16. The current status of the unrecovered Idaho PCA deferral balance as of
June 30 2003 is $27 843 108.
Status Report - Application for Extension
The details of the deferred cost balance as reflected in the Company s PCA account
are as follows:
DECISION MEMORANDUM
Unrecovered Balance at June 30, 2002
Net Deferral Activity (July 2002 - June 2003)
Amortizations Related to Surcharge Revenues
(July 2002 - June 2003)
Unrecovered Balance at June 30, 2003
$45 600 228
789 503*
(24 546,623)
$27 843 108
Deferral Activity Detail
Net Increase in Power Supply Cost
Centralia Capital and O&M Credit
PGE Monitization Accelerated Amortization
Transfer Small Generation Capital Costs & Interest
Intervenor Funding Payment
Interest
Net Deferral Activity (July 2002 - June 2003)
$23 383 629
817 996)
(13 855 680)
( 921 184)
138
999,596
$ 6 789 503
During the review period, A vista reports that Idaho s share of power supply expenses
exceeded the authorized level by $25 924 662. The Company states that power supply expenses
were higher than the authorized level due to several factors:
The largest factor was the sale of fixed price gas. Based on the average
purchase and sale price, the fixed price gas purchases added approximately
$13.1 million to Idaho s share of power supply expense. Hydro-generation
was approximately 12.9 aMW below the authorized level, which would
account for approximately $2.1 million of increased expense. Colstrip and
Kettle Falls together generated approximately 8 aMW above the authorized.
Rathdrum generated approximately 21 aMW below the authorized level due
in part to the relatively low price of electricity compared to natural gas costs.
The Company s other gas-fired generating plants, Northeast Turbine, Boulder
Park, and the Kettle Falls Combustion Turbine generated 2 aMW during the
period.
Other power supply expenses during the review period include a payment to
terminate a long-term power purchase with Enron and the final lease
payments of$3.7 million ($1.3 million Idaho share) related to the Kettle Falls
Bi-Fuel generating units. The $2.million Enron buy-out payment
($960 000 Idaho share) occurred in October 2002, and was recorded as a
power purchase expense. The Kettle Falls Bi-Fuellease payments began in
September 2001 and were included in the prior filing for the review period
ending June 2002.
Another factor driving the deferrals is the age of the authorized case. The
authorized case is based on loads, contracts and resources in place for the
period July 1999 through June 2000. During that period, the Company had
DECISION MEMORANDUM
several large off-system power sales that generated significant revenue.
Almost all of the sales have ended and, as such, the revenue is reduced which
is reflected in a reduction in Account 447, Sale for Resale, revenue of $72
million on a system basis ($24 million Idaho share). Purchased power
expense has also decreased from the authorized level due in part to several
long-term contracts ending. Purchased power expense, however, has
decreased by only $24 million on a system basis ($8 million Idaho share).
The Company plans to file a general rate case within the next year to reset the
authorized level of power supply revenues and expenses.
Avista contends that continuation of the current surcharge is not only justified by the
current level of unrecovered power cost deferrals, but is essential to the continued improvement
in the financial health of the Company. Investor concerns surrounding cash flows, deferral
balances, and the ability to recover costs in a timely manner have had an impact on the
Company s financings. The Company s credit ratings were lowered by credit rating agencies to
below investment grade in October 2001. Because of Avista s present credit ratings, debt is more
expensive. A vista contends that it is imperative for both the Company and its customers that
A vista continue to improve its financial condition so that investment grade credit ratings can be
restored and so that longer-term debt can be refinanced on more reasonable terms.
Current projections indicated that with continuation of the 19.4% surcharge, the PCA
deferral balance would reach zero in mid-2005. The actual point when the deferral balance
reaches zero is dependent upon factors such as hydroelectric conditions, wholesale market prices
contract changes, etc., during the relevant period.
The Company requests that the Commission continue the PCA surcharge for an
additional 12 months, beginning October 12, 2003 and continuing through October 11 , 2004.
The Company requests that its Application be processed pursuant to Modified Procedure, i., by
written submission rather than by hearing.
On August 27 , 2003 , the Commission issued a Notice of the Company s PCA filing
and scheduled dates in Lewiston (Sept. 08) and Coeur d' Alene (Sept. 09) for customers to
discuss Avista s PCA/energy issues with Commission Staff. The Commission in its Notice made
a preliminary determination as to the appropriateness of processing the Company s Application
under Modified Procedure, i., by written submission rather than by hearing, and established a
September 30 2003, comment deadline. Reference IDAPA 31.01.01.201-204. Comments were
filed by Commission Staff and a small number of the Company s customers. Staff recommends
DECISION MEMORANDUM
a $5 849 100 adjustment (net fuel expense for losses on natural gas combustion turbine (CT) fuel
sold rather than burned) to the deferral balance, a continuation of the existing 19.4% surcharge
and true-up in the Company s next PCA filing. Staff also proposes changes in the Company
Risk Management Policy.
On October 8 2003 , the Commission issued Order No. 29351 continuing the existing
19.4% Schedule 66 PCA surcharge for 60 days beyond the scheduled October 11 , 2003
expiration or until such time as the Commission might issue an Order accepting, rej ecting or
modifying the Application in Case No. A VU-03-06. The extension was authorized to provide
the Company an opportunity to file a written reply to Staff comments and to make a procedural
recommendation regarding Staff s proposed adjustment.
STAFF COMMENTS
Staff performed a review and audit of the amounts that went into the Company s PCA
deferral balance. Other than the net fuel expense item, Staff found the amounts recorded in the
purchased power, thermal fuel, CT fuel and power sales accounts to be correct and recommends
that they be included in the deferral balance as of June 30 2003. Staff notes that the PGE credit
is now fully amortized and will not be included in future PCA deferrals. In the current PCA
filing, the PGE credit contributed $13 855 680.
Interest Rate PCA Deferral Balance
Staff notes that on May 16, 2003 , Avista filed an Application in Case No. A VU-03-
4 requesting that the interest rate for the Company s Power Cost Adjustment (PCA) deferral
balance be set at a level higher than the rate for customer deposits. Staff and the Company
agreed to a compromise solution adopted by the Commission in Order No. 29323, dated
August 21 , 2003. As reflected in the Commission s Order, a 200 basis point increase will be
allowed in the interest applied to year end deferral balances during recovery based on the first
in/first out (FIFO) method of accounting. The customer deposit interest rate would continue to
apply to new deferral balances accrued during the calendar year. This interest rate methodology
began January 1 , 2003 and continues through June 30, 2005. The new interest methodology was
not applied in the current PCA case filed by the Company. Staff proposes to include the results
of the new methodology in this current PCA year s deferral balance and calculations. The result
of Staffs adjustment increases the current year s deferral amount by $256 727. This amount
reflects the application of a 200 basis point adder to the current year s customer deposit rate of
DECISION MEMORANDUM
2%, calculated on the existing balance throughout the months of January through June 2003; and
the application of the customer deposit rate of 2% on the new deferrals, which continue to be
calculated at simple interest.
As reflected in Staff s comments, the largest component of the Company s net
deferral activity is the Net Increase in Power Supply Costs. The total net increase in power
supply costs, $23 383 629 is comprised of the following items:
1. Purchased Power
2. Thermal Fuel
3. CT Fuel
4. Sales for Resale
5. PGE Capacity Revenue True Up
6. Potlatch 25 aMW
7. Kettle Falls Bi-Fuel
8. Net Fuel Expense - Loss on Natural Gas Resold
9. Idaho Retail Revenue Adjustment
10. Wood Power Inc. Amortized Expense
11. Reverse Coyote Test Power Sales
($7 083 766)
($5 942 944)
($948 195)
$21 605 030
($2,483 328)
260 572
102 506
$11 817 650
$651 882
$352 788
$51 434
Net Fuel Expense Loss on Natural Gas Resold
Staff in its comments speaks to each component of power supply costs and
specifically addresses the Net Fuel Expense portion. In the Company s last PCA case, A VU-
02-, Staff questioned the circumstances surrounding the acquisition and later sale of natural gas
purchased by the Company to fuel the Coyote Springs II CCCT (combined cycle combustion
turbine). The Company maintains that at the time natural gas was purchased, it was anticipated
that Coyote Springs II would be operational and more economical to operate than making market
energy purchases.As it turns out, Coyote Springs II was neither operational nor was it
economical to use the gas at the Company s other facilities, given the price of the gas with
previously purchased fixed-for-floating financial swaps. The effect is an abnormally high
percentage of hedged gas to serve available resources at prices found to be uneconomical when
compared to energy purchased from the market.
In Case No. AVU-02-, Staff proposed that the Commission withhold judgment on
$578 748 in net fuel expense incurred in June of 2002 to serve Coyote Springs until a more
complete evaluation was conducted regarding anticipated online dates, reasons for the
operational delay and timing of the sale of gas acquired for the use of the plant. Pending further
DECISION MEMORANDUM
investigation, the Commission in its Order removed the $578 748. As part of its current PCA
investigation, Staff has completed a comprehensive review of the gas purchase and sale
transactions that generated losses on fuel resold and the excess net fuel costs requested for
recovery in this case.
In March 2001 , A vista entered into two contracts to secure gas and gas transportation
for Coyote Springs to gas-fired power plant. Initially, Coyote Springs II was scheduled for
testing in early 2002 and was expected to be commercially available in July of 2002. The two
purchases for Coyote Springs with five corresponding financial swap transactions, are a
primary concern to Staff. These purchases and financial swaps are shown in detail on Staff s
Confidential Attachment C. The first gas supply contract (Deal A) was to be delivered
November 2001 through November 2004. The fixed-for-floating financial swaps associated
with this supply contract consist of two transactions. Since the delivery period did not begin for
another six months, the price for October 2004 was locked three and one-half years into the
future without additional documentation showing the analyses beyond October 2002. Additional
analyses that should have been fully documented with the swap order, Staff contends, should
include volatility analyses, price trend analyses and load requirements for the time period
involved.
The second gas supply contract (Deal B) was for delivery to begin June 2002 and
continue through October 31 , 2003. A vista entered into two fixed- for- floating financial swap
contracts that were subsequently combined into one contract, for the entire delivery period. This
transaction locked in the price of gas for a period of 17 months. Since the delivery period did not
being for another 13 months, the October 2003 price was locked two and one-half years into the
future.
Gas from both contracts was sufficient to operate Coyote Springs II at its full 180
MW generating capacity through October 31 2003. At the time the Deals were first entered into
and at the time that the prices were locked, forward prices for electricity for an 18-month period
were expected to be very high and the Company expected substantial purchased power cost
savings and/or sales for resale revenues from the gas purchases. During June of2001 , day ahead
electric market prices fell below $1001MWh for the first time in a year and by September they
were approximately $25 per MWh, which is near the historic normal wholesale electric price.
Given approximately $6 gas, the drop in electric prices made it uneconomical to operate any of
DECISION MEMORANDUM
Avista s gas-fired plants to make electricity. Instead Avista simply purchased its power needs on
the electric market and sold the gas back into the gas market at a loss because gas prices also had
declined.
In Avista s PCA filing last year, which covered the time period July 2001 through
June 2002, losses on the sale of gas on Deal A amounted to approximately $5.6 million and were
approved for recovery. The loss on Deal B last year was approximately $0.6 million ($578 748).
This amount was not recovered in the last PCA, but was deferred to the current PCA year for
evaluation. In this year s PCA, which covers July 2002 through June 2003, Avista has included
$11.8 million in losses due to gas sales. Staff contends that it is likely there will be more losses
on the sale ofthis gas through the end of the longest contract, which ends on November 1 2003.
In last year s Order No. 29131 , the Commission directed Staff to investigate and
assess the reasonableness of Avista s Risk Management Policy (Staff Confidential Attachment J)
and how it affects the Company s short-term resource acquisition decisions. The Company
Risk Policy addresses the purchase and sale of electricity as well as the purchase and sale of
natural gas acquired to generate electricity. In general, this policy defines a mechanism that
eliminates differences between loads and resources as the actual time need approaches. The
Company s Risk Policy typically extends 18 months out, and tracks surpluses and deficiencies
month by month down to projected needs in the coming month. As reflected in the Company
Risk Policy "this policy is intended to focus on short-term power and natural gas supply
management, meaning the period of 18 months forward from any current date, as they relate to
meeting near-term energy load obligations." Such a plan, Staff contends, is designed to reduce
the financial risks that might otherwise be associated with large quantity, long-term sales or
purchases made at a single point in time. In theory, Staff does not oppose entering into financial
swaps or hedges to fix the price of gas. However, Staff is concerned about the length of the
swaps that Avista entered into and the apparent lack of additional support 2~ and 3~ years in
the future.
The gas deals that Avsita entered into, Staff contends, were unusual. Avista Electric
had no recent history of entering into purchase or sales arrangements that went outside of its
normal 18-month position report planning period.A vista Gas Operations did not make
purchases outside of a 12-month period that it uses to balance its gas need for its gas customers.
Staff believes that the losses on the sale of gas from the two purchases resulted from substantial
DECISION MEMORANDUM
risks that the Company took when it locked in the price for large quantities of gas for a period of
time up to 3~ years after the date of the purchase. The risk substantially stems from the price
paid, the fact that the price was established at only two points in time approximately 30 days
apart, gas price levels and trends over time, the volume of gas purchased, the length of forward
analysis and the duration of the purchases.
Risks could have been reduced, Staff contends, if smaller quantities of two, three or
five thousand dth/day (decatherm/day) had been purchased over time instead of four financial
swaps entered into over the period of a month totaling 40 000 dth/day for much of the entire
three year period. Not only did the Company lock into the purchase side of the gas transaction at
historically high gas prices, in large volumes at essentially one point in time, Staff contends that
it failed to mitigate the risk by also securing some mechanism to lock into the power sale of the
transaction for the excess energy. Staff contends that the Company s decisions were contrary to
the previously cited principals of good risk management. The Company s Risk Policy allows for
purchases that exceed 18 months in the future with proper authorization. Although the purchases
were authorized, Staff contends that the documentation to support these substantially longer
transactions is lacking. The Deal tickets provided some explanation as to why the long-term
purchases were made at this point in time. The workpapers reiterate again and again that the
purchases were entered into for the sole purpose of securing financing for the Coyote Springs II
project. To the extent that the transactions were made for the purpose of financing Coyote
Springs II, Staff contends that they were to meet A vista s cash flow requirements and were not
necessarily associated with utility operations.
Whether the transactions were implemented for the purpose of obtaining project
financing or not, the effect of undertaking financial swaps beyond the generally accepted period
of 18 months as specified in the Company s Risk Policy was $39 465 033 in loses on a system
basis. This amount translates to $11 785 048 on an Idaho jurisdictional basis after sharing.
While Staff is critical of the Company with respect to its overall gas acquisition approach for
Coyote Springs II, Staff limits its recommended adjustment to losses associated with Deal B
during the period from June 2002 through June 2003. Gas losses incurred under Deal B, Staff
contends, carryall the risk concerns previously identified with one additional concern. The
purchase put the Company in a long position outside of established risk management limits.
Staff recommends that losses on the sale of Deal B gas not be allowed to be deferred for PCA
DECISION MEMORANDUM
recovery. The Deal B purchase, Staff contends, was speculative because the generation was not
needed for load; it focused on future price changes and was not documented and shown to reduce
business risk." Staff recommends disallowing the losses from Deal B for the months of June
2002 through June 2003, in the amount of $5 849 100, with associated carrying charges of
$87 343, for a total adjustment of$5 933 433.
Staff notes that the swaps on Deal B were entered with A vista Energy.The
Company s electric operations have claimed no dealings with A vista Energy so proper pricing
mechanisms or safeguards have not been established. Absent an approved mechanism, the
affiliate transactions with A vista Energy, Staff contends, should be priced at the lower cost or
market. Therefore, the losses on Deal B should be repriced at market with the Company
absorbing the loss rather than passing it to customers through the PCA. The loss from gas
captured in the Idaho PCA deferral balance amounts to $5 849 100 and reduced interest amounts
to $87 343, which reduces the deferral balance to $21 906 665 as of the end of June 2003.
Existing PCA rates are designed to recover approximately $23.6 million in the period. If PCA
rates were adjusted based on Staffs calculations the rates would be reduced from 19.4% to
18.0%. However, Staff proposes that existing PCA rates be continued until the next PCA
regardless of the final decision reached in this case. Rates can remain unchanged because in the
future any differences between deferred costs and PCA revenues including accrued interest will
be trued up.
Staff in its comments recounts the energy assistance programs available for low-
income customers. Staff notes that Avista continues to offer rebate programs to customers who
convert to energy efficient heating or water heating equipment. The Company also continued to
promote Comfort Level Billing to help customers level out payments over a 12-month period.
Staff in its filed comments proposes that the Commission accept the Company s PCA
filing with the following recommendations and modifications:
1. The current 19.4% surcharge be continued until the next PCA filing regardless of
the final decision reached by the Commission in this case. Staff also recommends any actual
remaining deferral balance at June 30, 2004, be subject to review by the Commission prior to
establishing a surcharge for any additional period of time, as provided for in Order No. 28876
Case No. A VU-01-11.
DECISION MEMORANDUM
2. The net fuel expense for losses on natural gas CT fuel sold rather than burned
under "Deal B" be denied for recovery in the PCA in the amount of $5 849 100 and $87 343
interest.
3. That the deferral balance be modified to include Staffs adjustments and
corresponding adjustments to the carrying charges.
4. The Company be required to work with the Commission Staff and customers in
developing an acceptable Risk Policy for the utilities division of A vista Corporation.
CUSTOMER COMMENTS
Staff notes that the Commission Staff held public workshops in both Lewiston and
Coeur d' Alene regarding A vista s proposed continuation of its 19.4% surcharge. One customer
attended the Lewiston workshop and no customers attended the Coeur d' Alene workshop. From
the time Avista filed its PCA through September 29 2003, the Commission received six written
comments from customers. The deadline for filing comments was September 30 2003. None of
those who commented were in favor of the continuation of the surcharge.
COMPANY REPLY
On October 3, 2003, Avista filed Reply Comments. Avista does not agree with
Staffs recommended disallowance of approximately $5.9 million of deferred costs associated
with certain natural gas costs for thermal generation. The transactions related to the costs at
issue, the Company contends, were entered into in the spring of 2001 , at a time when wholesale
electric prices were at unprecedented highs, federal regulators were continuing to refuse to
intervene, and A vista was facing the worst hydroelectric conditions in its history. The Company
believes that a careful review of the information available at the time the transactions were
entered into will show that the decisions were reasonable given the circumstances at the time.
A vista requests the opportunity to fully respond to Commission Staff s
recommendations through evidentiary hearings. However, following discussions with Staff
Avista states that the Company and Staff agree that it would be administratively efficient for the
Company to respond to Staff s recommendations in its upcoming general rate case, which A vista
plans to file in the first quarter of 2004. If evidentiary hearings were to proceed in this case, the
Company contends that they would likely overlap the general rate case proceedings.
DECISION MEMORANDUM
A vista recommends continuation of the existing surcharge rates until the next PCA
(through October 11 , 2004). Avista commits to fully responding to the issues raised by Staff in
this case, in its pre-file testimony in a general rate case, to be filed no later than March 31 , 2004.
COMMISSION DECISION
Avista has requested approved recovery of excess power costs deferred through June
2000 ($27 843 108) and further continuation of a 19.4% ($23.6 million) PCA surcharge.
Commission Staff in its filed comments recommends a disallowance of$5 849 100 in
net fuel expense (losses on sale of Coyote Springs II Deal B gas) together with $87 343 in related
carrying charge, for a total adjustment of $5 933,433. Staff contends that the purchase was
speculative and put the Company in a long position outside of established risk management
limits.
Commission Staff in its comments also recommends increasing the current year
deferral amount by $296 727 to reflect the effective January 1, 2003 approved change in the
interest rate methodology. Reference Order No. 29323.
Commission Staff recommends that the Company be directed to work with Staff and
customers in developing an acceptable Risk Policy for the utilities division of A vista
Corporation.
A vista in its filed Reply requests the opportunity to fully respond to Staff s proposed
net fuel adjustment ($5 933 433). It is Avista s preference that the issue be deferred until the
Company s next electric general rate case, to be filed no later than March 31 , 2004. Staff
supports the Company s request.
How does the Commission wish to handle Staff s proposed net fuel adjustment?
Defer to the Company s next general rate case? If not, does the Commission wish to establish
further scheduling in this case?
Does the Commission find it reasonable to approve Staffs interest adjustment to the
June 30, 2003 PCA balance?
Does the Commission find it reasonable to direct A vista to work with Staff and
customers to develop an acceptable Risk Management Policy?
DECISION MEMORANDUM
Does the Commission find it reasonable to approve further continuation of the
existing 19.4% ($23.6 million) PCA surcharge?
Scott Woodbury
Vld/M:A VUEO306
DECISION MEMORANDUM