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):  December 17, 2009

 

 

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.

Oregon General Rate Case Stipulation

 

On July 31, 2009, Idaho Power Company (“IPC”) filed a general rate case with the Public Utility Commission of Oregon (“OPUC”), requesting authority to increase IPC’s base rates for its Oregon customers.  On December 17, 2009, IPC entered into a stipulation with all active parties in the rate case to resolve most of the issues presented in the case (“Stipulation”).  The Stipulation was filed with the OPUC in the general rate case docket on December 17, 2009.  The parties to the Stipulation are IPC, the OPUC Staff, the Oregon Industrial Customers of Idaho Power, EP Minerals, and the Citizens’ Utility Board of Oregon (the “Parties”).

The Stipulation resolves all issues in the general rate case, and the Parties agree that the adjustments set forth in the Stipulation, and the rates resulting from those adjustments, are fair, just and reasonable, subject to two exceptions: (1) the Citizens’ Utility Board of Oregon’s (“CUB”) position on residential rate design and (2) the Oregon Industrial Customers of Idaho Power (“OICIP”) position on service reliability to industrial customers.  The positions of CUB and the OICIP are described further below.  The Parties otherwise agree in the Stipulation to support the Stipulation in the general rate case docket, and to recommend that the OPUC issue an order adopting the settlements contained in the Stipulation.

Following are some of the issues resolved in the Stipulation:

 

Rate Settlement: IPC’s annual revenue requirement in Oregon would increase approximately $5 million under the Stipulation, from $32.4 million to $37.4 million.  This represents an approximate 15.4 percent increase in IPC’s base rates in Oregon.  IPC’s application in the general rate case requested an annual revenue requirement increase of approximately $7.3 million, with a 22.6 percent base rate increase, based on a 2009 calendar year test period.

The Stipulation provides that IPC’s return on equity (“ROE”) should be set at 10.175 percent and IPC’s overall rate of return (“ROR”) should be set at 8.061 percent.  IPC’s application in the general rate case proposed an ROR of 11.25 percent and an ROR of 8.680 percent.  As described in the joint testimony accompanying the Stipulation, the Parties believe the ROE and ROR levels set forth in the Stipulation represent a reasonable compromise, and not outside the general range of ROE and ROR adopted by the OPUC for other Oregon electric utilities.  Further details on the ROE and ROR calculations, including the individual components in IPC’s assumed capital structure, are set forth in the Stipulation.

The Parties agree in the Stipulation to request a schedule for the remaining procedures in the general rate case docket consistent with a March 1, 2010 effective date for the new base rates, provided that such a schedule will allow CUB and OICIP adequate time to prepare their respective testimony on residential rate design and service quality.

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The Stipulation specifies that the acceptance of the rate increase adjustments is for the purposes of settlement only and does not represent acceptance of any methodology underlying the various adjustments, is not binding on Parties in future proceedings, and does not imply agreement on the merits of the adjustments.

Advanced Metering Infrastructure: The Parties agree in the Stipulation that it is appropriate to remove from the case capital expense associated with communication equipment acquired to implement IPC’s Advanced Metering Infrastructure (“AMI”) system, given that AMI has not yet been implemented in IPC’s Oregon jurisdiction.  However, the Parties recognize that IPC will in the future make a request to recover any prudently-incurred investment in such equipment once AMI is implemented in Oregon.  The Parties also recognize in the Stipulation that IPC may receive federal funds under the American Reinvestment and Recovery Act that will be used to subsidize certain additional smart grid technologies.  In the event such funds are received, they will be utilized as an offset to those investments of IPC which reduce the net rate base upon which IPC’s future returns will be determined.

Net Power Supply Expense:  The Stipulation addresses the methodology for calculating IPC’s net power supply expense, and provides that the level of net power supply expense recovery included in IPC’s base rates is $10.94 per megawatt-hour, and that this rate will become the base from which future annual power cost update rates will be determined.

Pension Expense:  IPC’s filed case did not include any expense related to pension.  On October 20, 2009, IPC filed an application with the OPUC proposing to account for pension expenses on a cash basis as opposed to accrual basis, with the plan to recover such expenses at some point in the future.  As a result of settlement discussions, the Parties agree that IPC should continue to account for pension expense on an accrual basis, consistent with SFAS 87.  Further, the Parties agree that the stipulated revenue requirement set forth in the Stipulation includes SFAS 87 pension expense.  If the OPUC adopts this provision, IPC agrees to withdraw its request to move to a cash basis accounting for pension expense.

Cost Allocation/Revenue Spread:

The Stipulation addresses cost allocation and revenue spread issues in paragraphs 11-13 of the Stipulation.  The Parties agree that IPC’s marginal cost approach to allocating costs is appropriate and should be adopted with two exceptions:  1) the Parties agree that at this time, transmission-related revenue requirement should be classified as 75 percent demand-related and 25 percent energy-related for the purpose of allocation to customer classes and 2) IPC has historically separated its embedded production costs into energy and demand components prior to their allocation.  Instead, the Parties agree in the Stipulation that the functionalized production revenue requirement should be allocated directly and on the basis of each schedule’s combined share of marginal demand and energy costs.  Because a pure cost of service revenue requirement allocation would result in relatively large increases for Agricultural Irrigation Service and Traffic Control Lighting Service, the Parties agree to cap the increases for those customer classes at 75 percent of their cost of service and spread the revenue shortfall to all other customer classes with the exception of Large Power Service-Transmission Voltage Level and Area Lighting Service which receive no increase.

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Rate Design:  Subject to CUB’s position on residential rate design discussed below, the Parties agree in the Stipulation that IPC’s proposed rate design in its general rate case filing should be adopted, with certain exceptions pertaining to IPC’s residential service charge, residential block rate pricing, and small general service customer energy charges, all as described in the Stipulation.

Rule F Modifications:  IPC agrees in the Stipulation to withdraw certain charges it had proposed in its general rate case filing for Rule F, Service Connection and Discontinuance.

Rule H: IPC agrees in the Stipulation that by March 31, 2010, it will file revisions to Rule H, New Service Attachments and Distribution Line Installations or Alterations.

Rule K: IPC agrees in the Stipulation to withdraw its proposed additional language to Rule K, paragraph 4, Protection of Electrical Equipment, and address any addition of the proposed language at future workshops to be held with Schedule 19 large power service customers and the OPUC Staff.

EnerNoc Program:  The Stipulation provides that IPC will evaluate the first year operational results of its EnerNoc peak demand reduction program in its Idaho jurisdiction, and share the results of its review (subject to confidentiality restrictions) with Schedule 19 large power service customers.  IPC also agrees in the Stipulation to file a third-party-operated, incentive–based, peak demand reduction program (such as the EnerNoc contract), which will be available to Schedule 19 large power service customers in Oregon during the 2010 summer peaking season.

Diesel Standby:  IPC commits in the Stipulation to include in its 2009 Integrated Resource Plan 1) a determination of the cost and viability of an incentive-based standby generation program targeted toward Schedule 19 large power service customers and 2) a description of IPC’s intent to develop such a program through a collaborative approach involving Schedule 19 large power service customers.  IPC commits to making this program available to its Schedule 19 large power service customers in Oregon, provided that it finds that the program will be cost-effective and in the best interests of its customers.

CUB’s Position:  CUB agrees with and supports all aspects of the Stipulation, except that CUB does not agree with the stipulated residential rate design.  More specifically, CUB does not support tiered rates for residential customers.  CUB will submit testimony to the OPUC, on January 19, 2010, in opposition to the residential rate design portion of the Stipulation.

OICIP Position:  OICIP also agrees with and supports all aspects of the Stipulation, except that OICIP seeks further review on the issue of service reliability for Schedule 19 large power service customers.  OICIP will submit testimony on this subject to the OPUC on January 19, 2010.

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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 Idaho Power Company 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:  the effect of  regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Federal Energy Regulatory Commission affecting our ability to recover costs and/or earn a reasonable rate of return including, but not limited to, the disallowance of costs that have been deferred; changes in and compliance with state and federal laws, policies and regulations  including new interpretations by oversight bodies, which include 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, of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties and costs of remediation that may or may not be recoverable through rates; 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, global climate change, and energy policies; 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; population growth rates and other demographic patterns; market prices and demand for energy, including structural market changes; increases in uncollectible customer receivables; fluctuations in sources and uses of cash; results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets and other 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, interest rates, credit spreads and other financial market conditions, as well as changes in government regulations, which affect the amount and timing 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 statements 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, 2008, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009, 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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ITEM 9.01     FINANCIAL STATEMENTS AND EXHIBITS

(d)  Exhibits

 

            Number          Description

 

            99.1                 Stipulation, dated December 17, 2009, filed with the Public Utility Commission of Oregon in UE 213

 

            99.2                 Joint Testimony of Idaho Power Company, the Staff of the Public Utility Commission of Oregon, the Oregon Industrial Customers of Idaho Power, EP Minerals, and the Citizens’ Utility Board of Oregon, dated December 16, 2009, filed with the Public Utility Commission of Oregon in UE 213

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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:  December 18, 2009

IDACORP, Inc.

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

 

 

 

IDAHO POWER COMPANY

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

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