app.ntc.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE PETITION OF AVISTA CORPORATION DBA AVISTA UTILITIES—WASHINGTON WATER POWER DIVISION (IDAHO) FOR PROPOSED MODIFICATIONS TO THE POWER COST ADJUSTMENTS (PCA) METHODOLOGY. )
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) CASE NO. AVU-E-01-1

NOTICE OF APPLICATION

NOTICE OF INTERVENTION DEADLINE

YOU ARE HEREBY NOTIFIED that on January 16, 2001, Avista Corporation dba Avista Utilities—Washington Water Power Division—Idaho (Avista; Company) filed an Application with the Idaho Public Utilities Commission (Commission) seeking approval of proposed modifications to its existing Power Cost Adjustment (PCA) mechanism. As justification for its proposed changes, the Company states that the cost of short-term power purchases has risen to unprecedented levels. The rising short-term market price for electric energy, the Company states, has resulted in a situation where Avista is forced to purchase power at prices that are higher than the price received when the power is sold to meet increased retail and wholesale system load requirements being experienced by the Company. The power supply expenses associated with meeting increased system load requirements, the Company notes, are not included in the PCA mechanism. The Company proposes to correct this omission.
Short-term market prices, the Company states, have also created a situation where a forced outage at either the Colstrip or the Kettle Falls generating plant would result in extremely high replacement costs. Power supply expenses associated with thermal plant forced outages, the Company notes, are not included in the current PCA mechanism. The Company proposes to correct this omission.
The Company is proposing that the PCA mechanism be amended effective January 1, 2001. The first deferral would occur in February 2001 for actual power costs incurred during the month of January 2001. The Company requests that the Commission rule on its request on or before February 28, 2001.
The amendments to the PCA deferral mechanism requested by the Company in greater detail are as follows:
Changes in system load requirements
The cost of power to serve changes in system load requirements is not included as part of the PCA mechanism. The Company contends that this cost is substantial and needs to be reflected in the PCA mechanism.
System load requirements, the Company states, have been impacted by increases in both retail and wholesale loads. Retail loads have increased due to load growth and colder than normal weather. Changes in wholesale loads have also impacted the amount of power that needs to be purchased. Wholesale loads are impacted by the expiration of both purchase and sale contracts and by increased takes under contracts because of the high short-term market prices.
Holding system load requirements to levels from the last general rate case in the existing PCA mechanism, the Company states, must be changed.
Actual thermal generation.
The current PCA mechanism models the amount of Colstrip and Kettle Falls thermal generation based on the short-term market price of power for the month and the incremental operating cost of the unit. Power supply expenses associated with thermal plant forced outages, the Company states, are not included in the current PCA mechanism because the mechanism is based on modeled rather than actual generation.
Calculation of costs for deferral.
The power costs for deferral purposes under the existing PCA mechanism are limited to the effect of short-term market prices on short-term transactions, Rathdrum turbine generation and fuel cost, hydro electric generation, the modeled impact of thermal generation and PURPA contracts. The Company is proposing to amend the PCA mechanism to include the impact of changes in retail and wholesale system load requirements and changes in actual thermal generation. Specific power supply accounts included for deferral purposes under the amended PCA mechanism would include Account 447—Sales for Resale, Account 501—Fuel (thermal), Account 547—Fuel (combustion turbine), and Account 555—Purchased Power. Deferred costs would be based on the difference between the actual revenues and expenses recorded in these accounts, and the normalized level for these accounts approved by the Commission in the last general rate case.

Centralia
The Centralia steam generating plant is included in the PCA based on fixed levels of “authorized” generation and “authorized” fuel costs. In May 2000 Centralia was sold. The Company is proposing to modify the PCA to reflect the elimination of Centralia generation and fuel costs as a result of the sale. The Company proposes to reflect a credit for Centralia operation and maintenance expense, depreciation, taxes and return on investment as these costs no longer exist as a result of the sale. Replacement power costs would be captured in the difference between actual and authorized levels of costs in Account 555—Purchased Power.
Coyote Springs 2
The Coyote Springs 2 project is a combined-cycle natural gas-fired combustion turbine with generation output of approximately 280 MW. The project is fully licensed. Construction of this plant began in January 2001. Completion of the project is expected in the summer of 2002. Under the modified PCA mechanism proposed, the increase in fuel costs associated with the plant as well as the impact on sales for resale and purchased power will be reflected in the calculation of PCA deferral. In addition, the Company proposes to reflect a charge in the PCA mechanism for operating and maintenance expense, depreciation, taxes and return on investment associated with the Coyote Springs 2 project until such time as these costs are reflected in general rates.
Portland General Electric (PGE) capacity sale
The PGE capacity contract revenues reflected in Account 447—Sales for Resale, the Company states, will be increased to include additional amortization for ratemaking purposes so that the total PGE contract revenue is equivalent to the revenue that would have occurred absent the monetization of the contract. Stated differently, the monthly PCA deferrals will not be impacted by the PGE contract monetization, because revenues will be adjusted to the level under the old contract and that same level of revenue is reflected in the authorized amounts from the last general rate case.
Retail Load Revenue Adjustment
Since actual system load requirements will determine the actual power supply revenues and expenses under the Company’s proposed changes to the PCA, the Company states, that it is appropriate to include a revenue adjustment for the difference between actual and authorized revenue in the amended PCA mechanism. Changes in wholesale sales contracts will be picked up in the calculation of the difference between actual and authorized revenues in Account 447. A retail revenue adjustment would be included to reflect the difference between actual and authorized retail revenue, adjusted for distribution costs to serve load growth.
Because the Company incurs incremental delivery cost to serve new load, the Company states it would not be appropriate to reflect the entire amount of difference between actual and authorized retail revenue in the deferral mechanism, as a portion of increased retail revenue is offset by increased costs to serve new load. The Company is proposing a distribution cost adjustment to retail revenue based on increases in customers by rate schedule. The difference between actual customers and authorized customers would be multiplied by distribution costs per customer from the Company’s last cost-of-service study to arrive at the distribution cost adjustment.
Risk Sharing
The Company is proposing to defer 90% of the differences described above under the amended PCA deferral mechanism. The remaining 10% of the differences would not be deferred and would impact earnings in the month they were incurred. The 90%/10% sharing would not be applied to the Centralia and Coyote Springs 2 adjustments for operation and maintenance expense, depreciation, taxes and return on investment. The 90%/10% sharing mechanism is being proposed as an incentive for the Company to keep power supply costs as low as possible and to reflect a sharing between customers and shareholders. The Company points out that it does not have any influence on the short-term market price of power.
Balancing Account Trigger
The current trigger for implementing a PCA rebate or surcharge is $3 million or about 2.5% of base revenues. Only two surcharges or rebates can be in place at one time. Two surcharges or rebates amount to $6 million or about 5% of base revenues. The Company is proposing to raise the limit on surcharges or rebates to $12 million or about 10% of base revenues. The Company suggests, however, that this limit be a guideline rather than a hard and fast rule. If circumstances arise that justify either a different trigger or limit amount, the Company proposes that it have the flexibility to structure its request to meet the circumstances.
Interest on Balancing Account
The Company proposes that the amended PCA mechanism include a calculation of interest using the same methodology approved for calculating interest on deferred natural gas cost balances (i.e., the customer deposit rate—reference O.N. 28624, Case No. AVU-G-00-4).
Periodic Reporting
The Company notes that it currently provides reports to the Commission on a monthly basis related to the deferrals and will continue to do so under the amended PCA mechanism. The reports would include all calculations and accounting entries.
Avista requests that the Commission adopt the procedures described in Rules 201-210—Modified Procedure contending that a public hearing may not be necessary.
COMMISSION FINDINGS
Avista in its filing requests that its Application be processed under Modified Procedure, i.e., by written submission rather than by hearing. Reference Commission Rules of Procedure, IDAPA 31.01.01.201-204. The Company also asks that any approved change in procedure be effective January 01, 2001. The Commission Staff advises us that it has outstanding production requests to the Company and has not completed its analysis. Staff asks that the Commission defer any decision regarding Modified Procedure until it and future parties are able to assess the reasonableness of such a request. The Commission finds the Staff request to be reasonable. However, we will not countenance unnecessary delay. When Staff completes its analysis, it should bring this matter back to us to establish further procedure. Regarding the Application and the Company’s requested relief, we note that no change in PCA methodology can be made without a Commission Order authorizing it. Therefore, unless and until further order is issued approving modifications, the PCA shall operate as it has been approved to do in the past.
YOU ARE FURTHER NOTIFIED that persons desiring to intervene in Case No. AVU-E-01-01 for the purpose of becoming a party, i.e., to present evidence, to acquire rights of cross-examination, to participate in settlement or negotiation conferences, and to make and argue motions must file a Petition to Intervene with the Commission pursuant to Rules of Procedure 72 and 73 of the Commission’s Rules of Procedure, IDAPA 31.01.01.072 and -.073. Persons intending to participate in this case as a formal party must file a Petition to Intervene on or before Friday, February 16, 2001.
YOU ARE FURTHER NOTIFIED that persons desiring to present their views without parties’ rights of participation and cross-examination are not required to intervene and may present their comments without prior notification to the Commission or to other parties.
YOU ARE FURTHER NOTIFIED that discovery is available in Case no. AVUE0101 pursuant to the Commission’s Rules of Procedure, IDAPA 31.01.01.221-234.
YOU ARE FURTHER NOTIFIED that the Company’s Application together with the filings of record can be viewed at the Commission’s office in Boise, Idaho and at the Company’s Idaho offices during regular business hours.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held pursuant to the Commission’s jurisdiction under Title 61 of the Idaho Code and the Commission will enter any final Order consistent with its authority under Title 61.
YOU ARE FURTHER NOTIFIED that all proceedings in this matter will be conducted pursuant to the Commission’s Rules of Procedure, IDAPA 31.01.01.000 et seq.
DATED at Boise, Idaho this day of January 2001.

DENNIS S. HANSEN, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

PAUL KJELLANDER, COMMISSIONER

ATTEST:

Jean D. Jewell
Commission Secretary

Vld/N:AVU-E-01-01_sw

NOTICE OF APPLICATION
NOTICE OF INTERVENTION DEADLINE 1

Office of the Secretary
Service Date
February 1, 2001