staff.pdf

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 1895

Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE SUBMISSION OF
THE STATUS REPORT OF AVISTA
CORPORATION AND APPLICATION FOR A
CONTINUATION OF A POWER COST
ADJUSTMENT (PCA) SURCHARGE.

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CASE NO. AVU-E-02-6

COMMENTS OF THE
COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of
Application, Notice of Modified Procedure and Notice of Comment/Protest Deadline issued on
August 28, 2002 submits the following comments.
On August 9, 2002, Avista Corporation doing business as Avista Utilities (Avista;
Company) filed an Application with the Idaho Public Utilities Commission (Commission)
requesting a continuation of the electric Schedule 66 Power Cost Adjustment (PCA) surcharge of
19.4% ($23.6 million) currently scheduled to expire on October 11, 2002. As reflected in this
filing, Avista states that the current status of the unrecovered PCA deferral balance as of June 30,
2002, is $45,600,228 for its Idaho jurisdiction. Avista is requesting that the Commission continue
the PCA surcharge for an additional 12 months, through October 11, 2003.
Staff proposes that the Commission accept the filing with the following recommendations
and modifications. Staff specifically recommends:
STAFF COMMENTS 1 SEPTEMBER 20, 2002
1. That the current surcharge of 19.4% be continued for another 12 months and the
Company be required to file a PCA status report 60 days prior to the expiration of the PCA rate
next year.
2. That the Company’s request to change the interest rate be denied and the existing rate
be continued. The interest rate mechanism as originally applied in the PCA modification case –
using the customer deposit rate, continues to be the appropriate rate in determining the carrying
charge.
3. That the variable costs for the small generation options be included in the deferral
balance for recovery. The costs included in the deferral balance that represent capital costs, i.e. for
the Kettle Falls small generation option, should be excluded from deferral balance and subsequent
recovery.
4. That the net fuel expense for natural gas CT fuel sold rather than burned be included in
the deferral balance for recovery, with the exception of the net expenses that were specifically
related to fuel expenses for the Coyote Springs plant. Staff recommends these expenses along
with similar expenses incurred after June 2002 be subject to a more detailed evaluation to be
completed by Staff and reflected in the next PCA review.
Staff also proposes a complete review of Avista’s risk management and mitigation policies
on an ongoing basis. A review of these types of transactions is timely given the changes in
electric and gas markets along with changes in the electric industry. It is also consistent with
reviews conducted with other utilities.
5. That the line item titled Gas Swaps, FAS 133 included by the Company in the deferral
calculation be removed.
6. That the deferral balance be modified to include Staff’s adjustments and the
corresponding adjustments to the carrying charges.

STAFF REVIEW
Staff’s review covered expenses incurred for the period July 2001 through June 2002.
Given the time allowed, Staff was able to look at a representative cross section of transactions
included in the Purchased Power account (FERC 555) and the Power Sales account (FERC 447).
Specifically reviewed was the price of the transaction when executed compared to other relevant
purchase/sales prices (Mid-Columbia index and futures) available at the time. If the transaction
STAFF COMMENTS 2 SEPTEMBER 20, 2002
price was competitive with other alternatives based on information available at that time, then it
was deemed reasonable to include it in the PCA. Based on the review of a sampling of
purchase/sale transactions, Staff concluded that the purchases and sales transactions appear
reasonable at the time they were entered
The Commission previously approved the PGE credit monetization. The monetization
accelerates the amortization from 18 years to fifteen months offsetting the current impact of low
water and high market prices. The PGE credit monetization is $2,309,280 per month and will
expire at the end of 2002.
The Buy-back programs were approved in the previous PCA period. Buy-back
expenditures of $2,169,263 were incurred during July through December 2001 in this PCA period.
Staff verified that the amounts are correct and have been recorded in the appropriate accounts and
are reasonable. Avista requested the programs be cancelled when they became uneconomical.
The largest component of above normal power supply costs deferred during the July 2001
through June 2002 time period were purchase/sales transactions. The Company quantifies above
normal purchased power costs of approximately $39 million with offsetting market sales of
approximately $8.4 million. These market transactions net to approximately $30.6 million of
$48.4 million of the above normal power supply deferrals booked in the year currently being
reviewed. Staff reviewed the reasons for the additional power supply costs provided by the
Company, poor water conditions and high market prices, and found them to be generally true.
Streamflows in the Clark Fork River, which generate energy at Avista’s two largest hydropower
facilities, Noxon and Cabinet, during 2001 were at the second lowest level recorded in more than
70 years of record. (Attachment D). Streamflows in the Columbia River where Avista has
hydropower long-term contract rights were the absolute lowest in recorded history. These low
stream flows caused Avista to generate less hydropower than normal and caused the Company to
buy more power than normal from the market to meet its loads.
Day-ahead market prices peaked in December 2000 and declined to less than $100 per
MWh in June of 2001, the month before the current period being audited began. It took several
more months for the price to return to the $20 to $30 per MWh level that was normal before the
price run-up. (Attachment E). During the first two months of the current PCA period, Avista
continued to purchase energy from the day-ahead market at abnormally high prices. The
Company also continued to incur abnormally high-energy costs associated with forward energy
STAFF COMMENTS 3 SEPTEMBER 20, 2002
purchases made prior to market price declines that began in June 2001. The Company’s current
risk management policy, in place at the time the forward energy purchases were made, establishes
specific deadlines for addressing load/resource imbalances. Projected imbalances can be fairly
large one year ahead of need, must be significantly reduced 6 months ahead of need and must be
completely eliminated one day ahead of need. This risk management policy required the
Company to make substantial energy purchases to serve needs for the second half of 2001 at pre-
June 2001 prices.
Staff has reviewed the Company’s Risk Management Policy, a sample of the Company’s
“Position Reports” showing load/resource positions and “Deal Tickets” that identify purchase and
sales quantities, prices and dates. Staff believes that market purchase and sales decisions were
reasonable based on good utility practice and information available at the time the decisions were
made. In addition the Staff believes that the 90/10 sharing of the above normal power supply
costs in this PCA filing provide the Company with an economic incentive to make the best
possible decision for customers since it is also the best possible decision for shareholders. The
interests of the Ratepayers and the Shareholders are aligned by the sharing. Good power supply
decisions benefit both groups and poor power supply decisions harm both groups.
Interest
The Company is currently using the customer deposit rate to calculate the interest on the
deferral balance. In its Application Avista has requested to use 6%, as granted to Idaho Power in
Order No. 29026. Staff recommends that the Company continue to use the customer deposit rate.
The customer deposit rate is currently 4% and is adjusted annually on the first of January. In
Order No. 29026, the Commission ordered Idaho Power to defer $11.5 million until the 2003-2004
PCA. Normally Idaho Power Company adjusts rates to recover the entire deferral balance in one
year. In that order the Commission states:
However, the Commission also recognizes the additional costs
associated with large deferral balances – particularly those extending
beyond the traditional one-year PCA recovery period. Thus, the
Commission finds in this instance that it is appropriate for the
Company to receive a higher interest rate than the current customer
deposit rate of 4% on the $11.5 million that will be deferred for
recovery beyond one-year. The Commission finds that 6% is a
reasonable rate.
STAFF COMMENTS 4 SEPTEMBER 20, 2002
Avista did not request a higher interest rate last year and has not justified a higher rate in
this case. While Idaho Power and Avista have similar PCAs, Idaho Power’s PCA deferral balance
has interest that accumulates only when the power supply costs are being deferred. Once those
costs are subject to recovery, interest is no longer calculated on the remaining deferral balance.
Avista’s PCA deferral balance continues to accrue interest while the deferred power costs are
being recovered in addition to receiving interest when the costs were being deferred. Receiving
interest on the deferral balance during the recovery period provides Avista additional
compensation for costs incurred. This difference in PCA mechanisms provides Avista with
sufficient carrying charge recovery making a change from the customer deposit rate unnecessary.
Small Generation Options
Avista pursued various projects that allowed it to avoid additional high-cost purchases of
energy from the short-term wholesale markets when the projects represented the lowest cost
resource options available at the time. These included the Boulder Park project, the Devils Gap
project, the Kettle Falls Bi-fuel project, and the Othello project. In addition to adding generation,
the Company was also able to increase the operations of the Northeast Combustion Turbines. The
Company also decreased spill thus increasing power generation at the Monroe Street generating
station on the Spokane River in Spokane Washington. With the exception of the Kettle Falls Bi-
Fuel project capital expenses, Staff believes the expenses incurred to operate these projects should
be included in the PCA. Operation of these projects resulted in benefits to customers by reducing
expenses over what they otherwise could have been. Therefore, Staff recommends approval of
expense recovery through the PCA subject to the 90/10-customer/company sharing provisions.
The following list provides a brief description of each small power project and the costs
requested for recovery in the current PCA deferral balance (July 1, 2001 – June 30, 2002).
Boulder Park - $8,423
The Boulder Park project includes six gas-fired reciprocating engines for a total of 25
megawatts. This credit reflects revenue generated from sales during project testing. The fuel
costs are included in Account 547, Combustion Turbine Fuel. This is new generation that is
owned by the Company. No capital costs are included in the deferral balance.
Devils Gap – $2,593,656
This is a temporary power project located at Devils Gap. The costs included in the deferral
balance are the lease costs for the 20 above ground diesel generators. During the period of high
STAFF COMMENTS 5 SEPTEMBER 20, 2002
market prices, Avista entered into contracts to lease generators for this project to reduce the
Company’s overall power cost. The subsequent decline in market prices warranted the lease
cancellation. The lease costs incurred prior to the cancellation were prudently incurred to secure
power at a cost lower than market. These costs are included in the PCA consistent with Order No.
29026, pp 8-11. No capital costs associated with this project were included in the deferral
balance.
Kettle Falls Bi-fuel - $384,856
This is a temporary generating project located at the Company’s Kettle Falls generating
facility. The generators were leased to reduce market power purchases and are included in the
PCA consistent with the rationale explained above for Devils Gap.
Capital costs associated with the Kettle Falls project in the amount of $56,598 were
included in the deferral balance. Staff recommends removal of these project capital costs and the
associated interest. This adjustment is consistent with Order No. 29026 (Case No. IPC-E-02-3),
where Idaho Power was denied recovery of the facilities charge that was determined to be like a
capital cost in their recent PCA filing. The Commission in Order No. 29100 stated, “Capital
expenditures and associated expenses that do not vary with plant output are properly recovered in
base rates following a rate case. The PCA was intended to allow utilities to timely recover
variable power supply costs…” The Kettle Falls BI-Fuel project expense included by the
company in this PCA is a capital expenditure that does not vary with plant output. Consequently,
these expenses are properly recovered in base rates following a rate case. Therefore, Staff
recommends that the capital expenditure and interest be removed from the deferral balance subject
to recovery through the PCA.
Othello - $852,131
The Company initiated plans in early 2001 to install a 23 MW combustion turbine at
Othello, Washington. The Othello project was cancelled, subsequent to the drop in the electric
power market in the second half of 2001. The costs included in this current PCA filing are for
generator lease costs. Although subsequently cancelled, these costs were reasonably incurred to
reduce the overall power cost based on conditions at the time and should be included in the PCA
as discussed above. No capital costs are included in the deferral balance.

STAFF COMMENTS 6 SEPTEMBER 20, 2002
Monroe Street Spill - $4,666
The Company was able to increase the generation at its Monroe Street plant on the
Spokane River. In March 2001, the Federal Energy Regulatory Commission (FERC) asked for
FERC licensees in the 11 western states to increase generation at existing hydro plants. Avista
temporarily modified their FERC license to stop the spill and increase generation at the Monroe
Street project. The additional costs incurred resulted from the Company’s agreement to make the
City whole for any reasonable loss of revenue at its Gondola ride due to the no spill operation.
Avista reimbursed the Spokane Parks Department for gondola revenue it would have otherwise
received.
Northeast CT Emissions/Lease Expense - $36,320
These costs are included in the PCA consistent with approval in the previous PCA filing,
AVU-E-01-11.
Net Fuel Expense
Avista includes costs for the natural gas CT fuel sold rather than burned on Company
Exhibit No. KON-2, line 38. The Company purchased natural gas on the forward market for use
in its leased and owned combustion turbine units. The Company’s decision to purchase natural
gas for power production in the future when the forward market price for energy was much higher
than the cost of gas fired generation. The choice to purchase natural gas was the most cost
effective alternative at that time to meet future load. Based on information available at the time,
Staff has concluded that the forward gas purchases were reasonable at the time they were entered.
To the extent purchased gas was not used to generate electricity, it was sold into the
market. The line item amount represents the net cost of gas or the difference between the price
paid for natural gas and the revenue received when unused gas was sold. After the purchases were
made, market energy prices began to decline. It became more cost effective to purchase energy
from the market than to generate using previously purchased gas. Under these conditions the
Company decided to sell its unused gas on the market.
Staff does not dispute the Company’s decision to purchase gas to meet future needs as an
alternative to purchases from the energy market. Nor does Staff dispute the Company’s decision
to sell unused gas and rely on purchases from the energy market when declining prices made it
more cost effective. However, Staff believes it is necessary for the Company to better explain
elements of its risk evaluation methodology that drives short-term resource acquisition decision-
STAFF COMMENTS 7 SEPTEMBER 20, 2002
making. For example, the Company needs to describe the criteria used to first establish its natural
gas fuel portfolio and then to determine the timing of its divestiture. Therefore, the Staff proposes
further investigation by working with the Company to identify and document the process used in
this area of decision-making.
In addition, Staff continues to have questions regarding the circumstances surrounding
acquisitions and then dispensation of natural gas to fuel the Coyote Springs CCCT. The Company
maintains that at the time natural gas was purchased, it was anticipated that Coyote Springs would
be operational and more economical to operate than making market energy purchases. As it turns
out, Coyote Springs was neither operational nor economical given the price of gas previously
purchased. 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.
Consequently, Staff proposes that the Commission withhold judgment on net gas costs of
$578,748 incurred in June of 2002 to serve Coyote Springs until a more complete evaluation is
conducted regarding anticipated online dates, reasons for the operational delay and timing of the
sale of gas acquired for use at the plant. Staff believes that the additional evaluation can be
conducted by Staff and included for review in the next PCA. The June costs represent a small
fraction of the net gas costs incurred for the plant that will be subject to review during the next
PCA period and does not change the requested surcharge in this case.
The current surcharge will recover about $23 million of the current $45 million deferral
balance. Even with Staff’s proposed adjustments and its proposal to delay a decision on the
Coyote Springs natural gas purchases of $578,748 until next year’s PCA filing, Staff is not
proposing that the surcharge amount change.
Gas Swaps and Financial Accounting Standards (FAS) 133
Staff recommends the removal of the line item labeled gas swaps and FAS 133 (Company
Exhibit KON-2, line 51). Avista includes two equal and opposite entries in the deferral balance,
one in December 2001, and one in January 2002. The entries are a tracking mechanism for
derivative accounting with FAS 133 and are not appropriate PCA items. Staff proposes to
eliminate these entries and the line item from the deferral calculations. There is no change in the
deferral balance as a result of these entries or Staff’s adjustment.

STAFF COMMENTS 8 SEPTEMBER 20, 2002
Staff Calculation of the Deferral Balance
Staff Attachment A shows the deferral balance as a result of Staff’s adjustments. The
difference between the Total Power Cost Deferral as calculated by Staff and the Company is
$636,882 as shown on line 20 of Staff Attachment A. The Company calculates the June 30, 2002
deferral balance to be $45,600,228 (Staff Attachment A, Line 9); Staff calculates the deferral
balance on June 30, 2002 to be $44,963,346 (Staff Attachment A, Line 22).
Rates
Avista proposes that the PCA rates approved last year for the period October 12, 2001
through October 11, 2002 remain in place for another year. The Company claims $60.7 million
dollars in deferrals with adjustments through June of 2002. (Attachment A). If the Staff proposed
reduction of $0.6 million is approved, the remaining deferred balance will be $12.9 after two years
of surcharge at $23.6 million/yr, assuming no new deferrals. The PCA deferral balance is
dynamic in that it changes every month. Therefore, the balance that would actually be set for
recovery at some future date is not known. However, because North Idaho water conditions are
near normal and market prices have returned to a normal range, the deferral balance may not
significantly increase and may even decrease. Treatment of Coyote Springs gas purchases already
transacted could significantly impact future deferrals. Staff supports the Company’s proposal to
leave current rates in place for another year and to reexamine PCA deferrals next year. Staff
proposes that the Company be required to file a PCA status report 60 days prior to the expiration
of the PCA rate next year.
At the Public Workshop presented in Sandpoint on September 18, 2002 three commercial
customers involved in the timber industry voiced concerns that the PCA rate impact on their costs
is substantial and one of them suggested that spreading PCA costs over more years would be
beneficial. In Idaho Power Company’s most recent PCA case the Commission approved the
spreading of PCA costs over a second year. Staff recognizes this as a rate design option.
However, Staff does not recommend this option to the Commission for the following reasons.
Quantified PCA deferrals will require two years to recover under the Staff and Company proposals
in this case. Delaying recovery of these deferrals further into the future brings the possibility of
additional years of poor water conditions, which could increase the deferral balance. The carry-
over balance would accrue additional interest charges, which would increase PCA rates for those
customers. It is also a concern that these customers only represent three customers in one or more
STAFF COMMENTS 9 SEPTEMBER 20, 2002
classes. It is not known whether or not other customers in the same customer class or classes
would want PCA costs spread over additional time periods.

CONSUMER ISSUES
The Application that Avista filed on August 9, 2002 in Case No. AVU-E-02-6 contained
both a customer notice and press release. Both met the requirements of Rule 102, Notices to
Customers of Proposed changes in Rates in the Utility Customer Information Rules (IDAPA
31.21.02). Avista began sending the notice to customers with the August 12, 2002, billing and
continuing through the entire billing cycle, which ended September 11, 2002.
Between August 9 and September 18, 2002, the Consumer Assistance Staff took comments
via telephone from one customer, questioning the need to “bail-out” Avista. The Commission has
received and placed in its case file twenty-three (23) written comments from customers. All
except one oppose the continuation of the surcharge approved in 2001. One customer commented
she had an all electric home and felt there should be “a break for those who use electricity for
everything, including heat.” Several commented that poor management should not be rewarded.
There were objections to continuing the surcharges because of questionable trading practices,
Enron and the FERC investigation. Most of the comments seem to indicate that customers do not
clearly understand the issues being considered in this case. Staff recommends that the Order
clarify to customers that this case only addresses the recovery of the purchased power costs.
Avista understands that the requested continuation of the surcharge will not alleviate the
burden many of its customers are already experiencing with high bills. To help customers more
easily budget, Avista offers Comfort Level Billing, which is a levelized payment plan that
averages a customer's annual bill into equal monthly payments. Customers can sign up at any time
for a 12-month plan that is renewed in the anniversary month each year. Avista evaluates the level
payment amounts quarterly and may adjust the payment, depending on usage, up to two times in a
year. Approximately 13,195 Avista customers take advantage of Comfort Level Billing. Avista
can also work out special payment arrangements if a customer is having difficulties paying. For
example, a customer can pay a set amount plus the current bill to catch up a past-due amount or
establish a payment plan for a set amount each month as long as that payment amount is
reasonable. Customers may contact Avista concerning payment arrangements at 1-800-227-9187.
STAFF COMMENTS 10 SEPTEMBER 20, 2002
In addition to the arrangements that Avista offers, The Low Income Home Energy
Assistance Program (LIHEAP), a federally funded program, is administered by the Idaho
Department of Health and Welfare, which subcontracts with Community Actions Agencies located
throughout Avista's service territory to deliver the services. Energy Assistance benefits are based
on income and the number of people in the family. Staff has learned that the qualifying guidelines
for LIHEAP have been changed so that fewer customers will be eligible for assistance during this
year’s heating season. Last year, customers whose income was 150% or less of the federal
poverty level qualified for assistance. For the 2002-03 heating season, the benefit level has been
lowered to 133% of the federal poverty level. Qualifying low income customers receive a lump
sum amount once during the heating season. Help is generally available from LIHEAP from
December 1 – April 30. The minimum amount of the LIHEAP dollar benefit for this year from
Health and Welfare is not yet available. Last year’s minimum benefit was $120.00. Locations
where customers may apply for energy assistance, updated each November, are available on the
Commission website (http://www.puc.state.id.us/). From November 1, 2002 through April 30,
2002, 1,264 Avista customers received energy assistance grants totaling $292,171.
Project Share is also administered by the Community Action Agencies in northern Idaho.
The guidelines for Project Share are more lenient, since the benefit is based more on need than
income. Project Share may be used once annually and the maximum award is $100. Project Share
is funded by donations from utility customers. In 2001 Avista Corporation made a $75,000
donation for both Idaho and Washington to Project Share. The money was included in the
contributions distributed monthly to the participating agencies. Project Share determines how
much each state will receive from the donation; Idaho’s portion was 30.09% monthly. For the
year 2002, Avista Corporation donated $100,000 to Project Share; Idaho received $35,000. Project
Share receives funds periodically throughout the year, not just during the heating season. Avista
also made a corporate donation of $75,000 to individual agencies to be distributed in a similar
manner to Project Share; Idaho Agencies received $22,700.
Avista has several rebate programs in place. Attachments B and C explain each rebate
program and a chart representing customers that have received rebates since January 1, 2002
through September 18, 2002.
On September 18, 2002, Commission Staff conducted a workshop in Sandpoint, Idaho and
presented information explaining the PCA mechanism and the current application.
STAFF COMMENTS 11 SEPTEMBER 20, 2002
STAFF COMMENTS 12 SEPTEMBER 20, 2002
Representatives of Avista were also present to answer questions. Seven customers of Avista,
including Senator Shawn Keough and Representatives John Campbell and George Eskridge,
attended the workshop. Three of the customers represented logging interests, who were especially
concerned over the adverse economic impact continuing the surcharge would have on their
businesses. Questions were raised and answered concerning the FERC investigation and Avista’s
participation in any of Enron’s trading strategies. As mentioned earlier in Staff’s comments, the
length of time for the surcharge was questioned since the customer felt a longer recovery period
that reduced rates would be more beneficial. One customer also wanted to compare Washington’s
PCA to Idaho’s. Another customer mentioned that local representatives of Avista had been very
helpful to him, but he did not find the same to be true when talking to upper management at
Avista; he wanted the Commission to consider that in its decision. All that attended were urged to
send comments outlining their particular concerns by the comment deadline of September 20,
2002.

Respectively submitted this day of September 2001.

___________________________
Scott Woodbury
Deputy Attorney General

Technical Staff: Keith Hessing
Kathy Stockton
Nancy Harman

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