UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported):  October 14, 2008

None

Former name or former address, if changed since last report.

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2.):

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

IDACORP, Inc.
IDAHO POWER COMPANY
Form 8-K

ITEM 8.01      OTHER EVENTS.

On October 14, 2008, Idaho Power Company (Company), the Staff of the Idaho Public Utilities Commission (Commission) and some of the Company's largest Idaho customers (collectively, the Parties) filed a Stipulation with the Commission which, if approved, would revise portions of the Company's Power Cost Adjustment (PCA) mechanism.  The PCA provides for annual adjustments to the rates charged to Idaho retail customers by tracking the Company's actual net power supply expenses (fuel and purchased power less off-system sales) and comparing them to net power supply expenses currently being recovered in retail rates.  The Stipulation is the result of three workshops held by the Parties and addresses six major aspects of the PCA.

PCA Sharing Methodology

The PCA sharing methodology currently allocates the costs and benefits of net power supply expenses between customers (90 percent) and shareholders (10 percent).  The Parties agreed to change the current 90/10 sharing ratio to 95 percent customers and 5 percent shareholders.  The Company would continue to recover 100 percent of the costs of energy purchased from PURPA qualifying facilities.  This change in sharing methodology would become effective on the first day of the month following Commission approval of the Stipulation.

Load Growth Adjustment Rate (LGAR)

The LGAR is an element of the current PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns.  The Commission-approved settlement of the 2007 general rate case reset the LGAR to $62.79 per MWh, but applied that rate to only 50 percent of the load growth beginning in March 2008.  In the Stipulation, the Parties agreed on a formula that, based on filed data from the 2008 general rate case, would produce an LGAR of $28.14 per MWh.  The LGAR formula contained in the Stipulation is expected to reduce the LGAR's impact on the Company's future ability to recover its actual power supply expenses.  This new methodology would become effective when new rates are implemented as a result of the 2008 general rate case.

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The Forecast

The PCA mechanism allows for the current collection or refund of forecasted net power supply expenses primarily based on projected April-July Brownlee Reservoir inflows provided by the National Weather Service's Northwest River Forecast Center (regression formula).  The Parties have agreed that the regression formula is no longer the best tool to forecast the Company's net power supply expenses.  In the Stipulation, the Parties agreed that the Company's more comprehensive operation plan forecast of net power supply expenses developed as a part of the Company's risk management process should replace the regression formula as the starting point for the PCA calculation.  The operation plan forecast may better match current collections with actual net power supply costs in the year they are incurred and result in smaller amounts being included in the following year's "true-up" rate.  This new methodology would become effective commencing with the Company's next PCA filing in April 2009.

Third Party Transmission Expense

The current PCA formula does not include transmission charges paid to third-parties to facilitate wholesale purchases and sales of energy.  The Parties agreed that third-party transmission expense, including losses, are a necessary component of net power supply expense and that deviations in these types of expenses from levels included in base rates should be reflected in PCA computations.  The Parties agreed that third-party transmission expense, including losses, would be included when the base is established as a result of the 2008 general rate case.

Power Supply Expense Distribution

To provide the financial community with more transparent and understandable financial communications, the Parties agreed that, for purposes of the PCA deferral calculation, the annual base net power supply expense should be distributed based upon the monthly shape of normalized revenues.  The Stipulation provides that this methodology would become effective when base rates are changed as a result of the 2008 general rate case.

Rate Spread/Revenue Allocation

PCA expenses are currently allocated to the Company's customer classes based upon class usage of energy as a percent of total system energy usage.  The Parties agreed that this rate spread and revenue allocation method needs to be re-examined following the Company's current general rate case to determine if this methodology needs to be changed.

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Certain statements contained in this Current Report on Form 8-K, including statements with respect to future earnings, ongoing operations, and financial conditions, are "forward-looking statements" within the meaning of federal securities laws.  Although IDACORP and IPC believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, these statements involve a number of risks and uncertainties, and actual results may differ materially from the results discussed in the statements.  Factors that could cause actual results to differ materially from the forward-looking statements include: changes in and compliance with governmental policies, including new interpretations of existing policies, and regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission, and the Oregon Public Utility Commission with respect to allowed rates of return, industry and rate structure, day-to-day business operations, acquisition and disposal of assets and facilities, operation and construction of plant facilities, provision of transmission services, including critical infrastructure protection and system reliability, relicensing of hydroelectric projects, recovery of power supply costs, recovery of capital investments, present or prospective wholesale and retail competition, including but not limited to retail wheeling and transmission costs, and other refund proceedings; changes arising from the Energy Policy Act of 2005; changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or other taxing jurisdiction, litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and penalties and settlements that influence business and profitability; changes in and compliance with laws, regulations and policies including changes in law and compliance with environmental, natural resources, endangered species and safety laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions or global climate change; global climate change and regional weather variations affecting customer demand and hydroelectric generation; over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities; construction of power generation, transmission and distribution facilities, including an inability to obtain required governmental permits and approvals, rights-of-way and siting, and risks related to contracting, construction and start-up; operation of power generating facilities including performance below expected levels, breakdown or failure of equipment, availability of transmission and fuel supply; changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities; blackouts or other disruptions of Idaho Power Company's transmission system or the western interconnected transmission system; impacts from the formation of a regional transmission organization or the development of another transmission group; population growth rates and other demographic patterns; market prices and demand for energy, including structural market changes; fluctuations in sources and uses of cash; results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by factors such as credit ratings and general economic conditions; actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria; changes in interest rates or rates of inflation; performance of the stock market and changes in interest rates, which affect the amount of required contributions to pension plans, and the reported costs of providing pension and other postretirement benefits; increases in health care costs and the resulting effect on medical benefits paid for employees; increasing costs of insurance, changes in coverage terms and the ability to obtain insurance; homeland security, acts of war or terrorism; natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind and fire; adoption of or changes in critical accounting policies or estimates; and new accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.  Any such forward-looking statement should be considered in light of such factors and others noted in the companies' Annual Report on Form 10-K for the year ended December 31, 2007, the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008 and other reports on file with the Securities and Exchange Commission.  Any forward-looking statement speaks only as of the date on which such statement is made.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned hereunto duly authorized.

Dated:  October 15, 2008

IDACORP, Inc.

 

By:   /s/ Darrel T. Anderson
Darrel T. Anderson
Senior Vice President -
Administrative Services
and Chief Financial Officer

IDAHO POWER COMPANY

 

By:   /s/ Darrel T. Anderson
Darrel T. Anderson
Senior Vice President -
Administrative Services
and Chief Financial Officer5