SECTION 13 OR 15(d) OF THE
Date of Report (Date of earliest event reported): March 5,
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)
Item 8.01 Other Events
November 18, 2009 meeting, the Compensation Committee (the Compensation
Committee) of the Boards of Directors of IDACORP, Inc. (IDACORP) and Idaho
Power Company (IPC) adopted the following policy regarding change-in-control
the Compensation Committee of IDACORP and Idaho Power Company hereby adopts the
following policy with respect to executive change-in-control agreements
regarding (1) single trigger payments triggered by a change-in-control
without a termination of the executives employment, (2) modified single
trigger payments triggered by a change-in-control plus termination of employment
by the executive for any reason and (3) excise tax gross up provisions:
Subject to the terms and conditions set forth in this policy, it shall be the Compensation Committees policy not to approve the inclusion of single trigger or modified single trigger payment provisions or excise tax gross-up provisions in change-in-control agreements initially entered into on or after the date hereof.
Executives who were entitled to receive modified single trigger payments and/or an excise tax gross-up pursuant to the terms and conditions of a change-in-control agreement entered into prior to the date hereof will be grandfathered and will continue to be entitled to such modified single trigger payments and/or excise tax gross-up in the form and on the terms included in such executives change-in-control agreements as in effect on the date hereof.
Pursuant to this
change-in-control agreement policy, the Compensation Committee approved a new
form of change-in-control agreement (the CIC Agreement) for IDACORP and IPC
executives at its March 17, 2010 meeting. The CIC Agreement does not include
any tax gross-up provisions or any single trigger or modified single trigger
payment provisions. The other terms of the CIC Agreement are consistent with
the change-in-control agreement described in IDACORPs 2009 proxy statement,
which was filed with the Securities and Exchange Commission on April 6, 2009. A
copy of the CIC Agreement is filed as Exhibit 10.1 hereto.
Memorandum of Understanding with PacifiCorp
On March 5, 2010, IPC and PacifiCorp (PacifiCorp) entered into a Memorandum of Understanding (the MOU). The MOU establishes a process for IPC and PacifiCorp to negotiate in good faith to attempt to reach an agreement on the termination of existing transmission agreements between IPC and PacifiCorp and the terms of new agreements relating
to the ownership of transmission facilities. If IPC and PacifiCorp have not executed the definitive agreements identified in the MOU by September 1, 2010, subject to extension, the MOU will terminate. The MOU may be terminated by either party at any time, at the sole discretion of the terminating party, without any penalty or liability.
IPC and PacifiCorp are parties to existing transmission capacity rights agreements identified in the MOU (the Legacy Agreements), including the Restated Transmission Services Agreement and the Agreement for Interconnection and Transmission Services discussed in IPCs and IDACORPs Annual Report on Form 10-K for the Year Ended December 31, 2009 (the 2009 Form 10-K), which grant to PacifiCorp certain transmission capacity rights over portions of IPCs existing transmission system. The Legacy Agreements also include a memorandum of understanding and a permitting cost sharing agreement for the Gateway West transmission line National Environmental Policy Act process.
Pursuant to the MOU, IPC and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate the Legacy Agreements and replace the transmission arrangements with new agreements discussed below.
Purchase and Sale Agreements, Joint Ownership and Operation of
Existing Transmission Facilities
Pursuant to the MOU, IPC and PacifiCorp will negotiate in good faith to attempt to reach an agreement on one or more purchase and sale agreements pursuant to which IPC will sell to PacifiCorp an undivided ownership interest in certain of its transmission facilities identified in the MOU, and PacifiCorp will sell to IPC an undivided ownership interest in certain of its transmission facilities identified in the MOU, subject to regulatory and board of directors approval. Each of the purchase and sale agreements will specify the scope of each partys ownership interests in the facilities. Each partys allocable transmission capacity in these facilities is expected to satisfy in part its respective obligation for transmission capacity as evaluated under the termination of the Legacy Agreements and capacity expansion responsibilities under its Open Access Transmission Tariff.
In connection with these purchases and sales, IPC and PacifiCorp will also negotiate in good faith to attempt to reach agreements to govern the interconnection of their systems and the joint ownership, operation and maintenance of the facilities. These agreements will designate one of the parties to serve as operator of each facility and will specify cost sharing related to operation, maintenance and capital improvements to the facilities.
Joint Development Projects
Pursuant to the MOU, IPC and PacifiCorp will negotiate in good faith to attempt to reach an agreement to jointly develop and construct three transmission projects identified in the MOU, including the 500 kV Boardman to Hemingway transmission line discussed in the 2009 Form 10-K. The other two projects are part of the Gateway West Project, which is also discussed in the 2009 Form 10-K: the 500 kV transmission line from Populus to Cedar Hill to Hemingway,
including a new Cedar Hill 500 kV station, and the 500 kV transmission line from Midpoint to Cedar Hill. The parties will also negotiate in good faith to attempt to reach a joint ownership, operation and maintenance agreement for the projects, including each partys rights to a specified transmission capacity on each of the lines.
A summary of the MOU is filed as Exhibit 99.1 hereto.
Election of New Chairman
At its meeting on March 18, 2010, the Boards of Directors of IDACORP and
IPC elected Gary G. Michael to serve as Chairman of both boards upon the
retirement of the current Chairman, Jon H. Miller, effective immediately prior
to the Annual Meeting of Shareholders on May 20, 2010. Mr. Miller, who is 72
and has served as Chairman of both boards since 1999, is retiring from the
boards in accordance with the mandatory retirement provisions of the Bylaws.
Mr. Michael has served on the Boards of Directors of IDACORP and IPC since 2001. He is Chairman of the Corporate Governance Committee and a member of the Executive Committee. He previously served as Chairman of the Audit Committee. Mr. Michael, who is 69, served as Chairman of the Board and Chief Executive Officer of Albertsons, Inc., a food-drug retailer, from 1991-2001. Mr. Michael is also a director of The Clorox Company since 2001; Questar Corporation, Questar Gas and Questar Pipeline since 1994; and Graham Packaging Company, Advisory Board, since 2002.
Idaho Public Utilities Commission Filings
Fixed Cost Adjustment Mechanism
On March 12, 2007, the Idaho Public Utilities Commission (IPUC) approved the implementation of a fixed cost adjustment mechanism (FCA) pilot program for IPCs residential and small general service customers. The FCA is a rate mechanism designed to remove IPCs disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. In the FCA, for each customer class, the number of customers is multiplied by a fixed cost per customer. The cost per customer is based on IPCs revenue requirement as established in a general rate case. This authorized fixed cost recovery amount is compared to the amount of fixed costs actually recovered by IPC. The amount of over- or under-recovery is then returned to or collected from customers in a subsequent rate adjustment. The pilot program began on January 1, 2007 and ran through 2009, with the first rate adjustment effective June 1, 2008 and subsequent rate adjustments effective June 1 of each year during its term.
On March 15, 2010, IPC filed an application requesting recovery of $6.3 million above the fixed costs authorized in base rate for the net under-recovery of fixed costs during 2009, to become effective on June 1, 2010 and to remain in effect until May 31, 2011. This amount is a $3.6 million increase over amounts recovered in the previous year of the program and would represent the final annual rate adjustment under the three-year FCA pilot program. On October 1, 2009,
filed an application with the IPUC seeking authority to make the FCA mechanism
permanent beginning January 1, 2010. That application is still pending.
Advanced Metering Infrastructure
Metering Infrastructure (AMI) project provides the means to automatically
retrieve energy consumption information, eliminating manual meter reading
On March 15, 2010, IPC filed an application with the IPUC requesting authority to increase its rates by approximately $2.4 million in its Idaho jurisdiction due to the inclusion of AMI investment in rate base for the 2010 test year. IPCs request also reflects the reduction in investment and the accelerated amortization costs related to the removal of current metering equipment, as well as reductions in operating expenses that accompany the changes in plant investment. IPC seeks an effective date for the rate increase of June 1, 2010.
IPC has calculated a revenue requirement of $2.4 million in the Idaho jurisdiction for the 2010 test year AMI investment. IPC has requested that this requirement be recovered through a uniform percentage rate increase of 0.33 percent for IPCs affected customer classes: residential, small commercial, large general-secondary, irrigation-secondary, and metered lighting, effective June 1, 2010, for service provided on and after that date.
Idaho Power Company Cash Contribution to Defined Benefit Pension Expense
On October 20, 2009, IPC filed an application with the IPUC to implement a mechanism to track and recover annually cash contributions made to the pension plan. On February 17, 2010, the IPUC issued an order denying implementation of an annual tracking mechanism but authorizing IPC to request recovery, through a rate case proceeding, of imminent, but as yet unpaid, pension plan contributions that have been determined by IPCs actuary as known-and-measurable expenses to be incurred.
On March 15, 2010, IPC filed an application with the IPUC requesting authority to increase its base rates to recover $5.4 million of cash contributions to defined benefit pension expenses, representing the Idaho-allocated portion of a cash contribution IPC is required to make for the plan year for IPCs pension plan beginning on January 1, 2009. IPC is scheduled to make the cash contribution on September 15, 2010, the extended filing date for IPCs 2009 federal income tax return. IPCs application requests authority to recover the $5.4 million cash contribution over a one-year amortization period of June 1, 2010 through May 31, 2011, with rate adjustments becoming effective on June 1, 2010.
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 and are intended to qualify for the safe
harbor from liability established by the Private Securities Litigation Reform Act of 1995. 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, 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.
Item 9.01 Financial Statements and Exhibits
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: March 24, 2010
INDEX TO EXHIBITS