ITEM 1. BUSINESS
OVERVIEW:
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.
IDACORP announced in 2002 that IE, a marketer of electricity and natural gas, would wind down its operations.
IDACORP's other subsidiaries include:
Ida-West Energy (Ida-West) - developer and manager of independent power projects;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services, Inc. (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider; and
IDACOMM - provider of telecommunications services.
At December 31, 2002, IDACORP had 1,942 full-time employees. Of these employees, 1,700 are employed by IPC.
IDACORP has identified two reportable business segments, the regulated utility operations of IPC and the energy marketing activities of IE. IPC and IE contributed 94 percent and five percent to consolidated operating revenues, respectively, during the year ended December 31, 2002. Financial information relating to amounts of sales, revenue, net income and total assets of IDACORP's operating segments is presented in Note 12 to the Consolidated Financial Statements and below in "Utility Operations" and "Energy Marketing."
IDACORP and IPC make available free of charge their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the Securities and Exchange Commission, through their website at www.idacorpinc.com.
UTILITY OPERATIONS:
IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC is involved in the generation, purchase, transmission, distribution and sale of electric energy in a 20,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 855,000. IPC holds franchises in 70 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon. As of December 31, 2002, IPC supplied electric energy to over 412,000 general business customers.
IPC owns and operates 17 hydroelectric power plants and one natural gas-fired plant and shares ownership in three coal-fired generating plants. These generating plants and their capacities are listed in Item 2
ITEM 2. PROPERTIES
IPC's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, one natural gas-fired plant located in southern Idaho and interests in three coal-fired steam electric generating plants. The system also includes approximately 4,657 miles of high voltage transmission lines; 22 step-up transmission substations located at power plants; 18 transmission substations; seven transmission switching stations; and 208 energized distribution substations (excluding mobile substations and dispatch centers).
IPC holds FERC licenses for its 13 hydroelectric projects. These and the other generating stations and their capacities are listed below:
(a) Renewed on a year-to-year basis; application for relicense is pending.
(b) IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman. Amounts shown represent IPC's share only.
At December 31, 2002, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 22 years; transmission system and substations, 20 years; and distribution lines and substations, 16 years. IPC considers its properties to be well maintained and in good operating condition.
IPC owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the FPA and reservoirs and other easements. IPC's property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, IPC's property is subject to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, IPC of such properties.
Idaho Energy Resources Co. owns a one-third interest in certain coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant.
Ida-West holds investments in nine operating hydroelectric plants with a total generating capacity of 45 MW. These plants are located in Idaho and California.
RELICENSING OF HYDROELECTRIC PROJECTS:
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size and complexity of the project. Currently, the licenses for five hydro projects have expired. These projects continue to operate under annual licenses until the FERC issues a new permanent license. Three more hydro project licenses will expire by 2010.
IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric projects. The licenses for the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon) and the Swan Falls project expire in 2005 and 2010, respectively. IPC is currently engaged in procedures necessary to file timely license applications for these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, IPC anticipates that it will relicense each of the eight projects.
Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls projects. New FERC licenses are anticipated in 2003. While the actual environmental costs of protection, mitigation and enhancement (PM&E) measures and other costs associated with the relicensing of the projects will not be known until the new licenses are issued by the FERC, costs associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million during the first five years of the licenses and $28 million over the following 25 years.
A final EIS has been issued in October 2002 for the CJ Strike project and a new FERC license is expected in 2003. While the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC, costs associated with the license (assuming a 30-year license) are expected to total approximately $9 million during the first five years of the license and $38 million over the following 25 years.
The four Mid-Snake River projects, Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, and the CJ Strike projects, may affect five species of snails listed under the Endangered Species Act. See discussion in the Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."
The Upper and Lower Malad project license expires in July 2004 and the new license application was filed in July 2002. The application is proceeding through the normal FERC licensing process. The application includes proposed PM&E measures estimated to total (assuming a 30-year license) approximately $1 million during the first five years of the license and $3 million over the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.
The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of IPC's hydro generation capacity and 40 percent of its total generating capacity. IPC developed its draft license application with the assistance of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. The draft license application was issued in September 2002 and the final application will be filed in July 2003. The draft application includes proposed PM&E measures estimated to total approximately (assuming a 30-year license) $78 million during the first five years of the license and $100 million during the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.
At December 31, 2002, $50 million of pre-relicensing costs were included in Construction Work in Progress (CWIP) and $6 million of pre-relicensing costs were included in Electric Plant in Service. The pre-relicensing costs are recorded and held in CWIP until a new permanent license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Pre-relicensing costs as well as costs related to the new licenses, as referenced above, will be submitted to regulators for recovery through the rate-making process.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 8 to the Consolidated Financial Statements.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages and positions of all of the executive officers of IDACORP, Inc. and Idaho Power Company are listed below along with their business experience during the past five years. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was elected.
IDACORP, Inc.
Name, Age and Position
Business Experience During Past Five Years
Jan B. Packwood, 59
President and Chief Executive Officer
Appointed May 30, 1999. Mr. Packwood was President and Chief Operating Officer from February 2, 1998 to May 30, 1999.
J. LaMont Keen, 50
Executive Vice President
Appointed March 1, 2002. Mr. Keen was Senior Vice President, Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002, Senior Vice President-Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from February 2, 1998 to March 15, 1999.
**Richard Riazzi, 48
Executive Vice President
Appointed March 1, 2002. Mr. Riazzi was Senior Vice President, Generation and Marketing from March 15, 1999 to March 1, 2002, Vice President - Marketing and Sales from January 14, 1999 to March 15, 1999 and Vice President - Marketing and Sales for Idaho Power Company from January 9, 1997 to March 15, 1999.
*Darrel T. Anderson, 44
Vice President, Chief Financial Officer and Treasurer
Appointed March 1, 2002. Mr. Anderson was Vice President, Finance and Treasurer from May 5, 1999 to March 1, 2002.
*Bryan A. B. Kearney, 40
Vice President and Chief Information Officer
Appointed March 15, 2001.
*Gregory W. Panter, 54
Vice President - Public Affairs
Appointed April 1, 2001.
*Robert W. Stahman, 58
Vice President, General Counsel and Secretary
Appointed February 2, 1998.
*Marlene K. Williams, 50
Vice President - Human Resources
Appointed March 1, 2002.
*These IDACORP, Inc. executive officers serve in the same capacities at Idaho Power Company. For these officers' business experience during the past five years, please refer to the next table.
**Mr. Riazzi has resigned from IDACORP, Inc. effective March 31, 2003 as part of the continued wind down of IDACORP Energy.
Idaho Power Company
Name, Age and Position
Business Experience During Past Five Years
Jan B. Packwood, 59
Chief Executive Officer
Appointed March 1, 2002. Mr. Packwood was President and Chief Executive Officer from May 30, 1999 to March 1, 2002 and President and Chief Operating Officer from September 1, 1997 to May 30, 1999.
J. LaMont Keen, 50
President and Chief Operating Officer
Appointed March 1, 2002. Mr. Keen was Senior Vice President-Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002, Senior Vice President-Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from March 14, 1996 to March 15, 1999.
James C. Miller, 48
Senior Vice President - Delivery
Appointed November 18, 1999. Mr. Miller was Vice President - Generation from July 10, 1997 to November 18, 1999.
Darrel T. Anderson, 44
Vice President, Chief Financial Officer and Treasurer
Appointed March 1, 2002. Mr. Anderson was Vice President-Finance and Treasurer from May 5, 1999 to March 1, 2002, Corporate Controller from January 25, 1999 to May 5, 1999, Executive Vice President of Finance and Operations at Applied Power Corp. from June 5, 1998 to January 25, 1999, and Corporate Controller from February 26, 1996 to June 5, 1998.
John R. Gale, 52
Vice President, Regulatory Affairs
Appointed March 15, 2001. Mr. Gale was General Manager of Pricing & Regulatory Services from 1997 to 2001.
Bryan A.B. Kearney, 40
Vice President and Chief Information Officer
Appointed November 18, 1999. Mr. Kearney was Vice President and Chief Technology Officer at Bear Creek Corp from 1998 to1999 and Chief Information Officer for Shasta County, California from 1996 to 1998.
Gregory W. Panter, 54
Vice President - Public Affairs
Appointed April 1, 2001. Mr. Panter was self-employed with Panter & Associates from 1989 to 2001.
John P. Prescott, 46
Vice President - Power Supply
Appointed November 18, 1999. Mr. Prescott was Vice President of Business Development for IDACORP Technologies, Inc. from August 1999 to November 18, 1999, and President and Treasurer of Stellar Dynamics from October 5, 1995 to August 1999.
Robert W. Stahman, 58
Vice President, General Counsel and Secretary
Appointed July 13, 1989.
Marlene K. Williams, 50
Vice President - Human Resources
Appointed May 5, 1999. Ms. Williams was Director of Human Resources at Arizona Public Service prior to May 5, 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
IDACORP, Inc.'s (IDACORP) common stock (without par value) is traded on the New York Stock Exchange and the Pacific Exchange. At December 31, 2002, there were 20,088 holders of record and the year-end stock price was $24.83 per share.
The outstanding shares of Idaho Power Company (IPC) common stock ($2.50 par value) are held by IDACORP and are not traded. IDACORP became the holding company of IPC on October 1, 1998.
The following table shows the reported high and low sales price of IDACORP's common stock and dividends paid for the years 2002 and 2001 as reported in the consolidated transaction reporting system.
The amount and timing of dividends payable on IDACORP's common stock are within the sole discretion of IDACORP's Board of Directors. The Board of Directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP's financial position and results of operations, legislative and regulatory developments affecting the electric utility industry in general and IPC in particular, competitive conditions and any other factors the Board of Directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily IPC.
IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC paid dividends to IDACORP of $70 million annually in 2002, 2001 and 2000.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The above data should be read in conjunction with IDACORP's Consolidated Financial Statements and Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.
The above data should be read in conjunction with Idaho Power Company's Consolidated Financial Statements and Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in thousands unless otherwise indicated. Megawatt hours (MWh) in thousands).
INTRODUCTION:
In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and subsidiaries (IDACORP) and Idaho Power Company and its subsidiary (IPC) are discussed. IDACORP is a holding company formed in 1998 as the parent of IPC, IDACORP Energy (IE) and several other entities.
IPC is an electric utility with a service territory covering over 20,000 square miles, primarily in southern Idaho and eastern Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.
IDACORP announced in 2002 that IE, a marketer of electricity and natural gas, would wind down its operations.
IDACORP's other significant operating subsidiaries are:
Ida-West Energy (Ida-West) - developer and manager of independent power projects;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services, Inc. (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider; and
IDACOMM - provider of telecommunications services.
As you read the MD&A, it may be helpful to refer to the Consolidated Financial Statements of IDACORP and IPC which present the financial position at December 31, 2002 and 2001, and the results of operations and cash flows for each company for the years ended December 31, 2002, 2001 and 2000.
FORWARD-LOOKING INFORMATION:
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), IDACORP and IPC are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of IDACORP or IPC in this Annual Report on Form 10-K, any Quarterly Report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions, and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward-looking statements:
changes in governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;
litigation resulting from the energy situation in the western United States;
economic, geographic and political factors and risks;
changes in and compliance with environmental and safety laws and policies;
weather variations affecting customer energy usage;
operating performance of plants and other facilities;
changes in environmental conditions and requirements;
system conditions and operating costs;
population growth rates and demographic patterns;
pricing and transportation of commodities;
market demand and prices for energy, including structural market changes;
changes in capacity and fuel availability and prices;
changes in tax rates or policies, interest rates or rates of inflation;
changes in actuarial assumptions;
adoption or changes in critical accounting policies or estimates;
exposure to operational, market and credit risk in energy trading and marketing operations;
changes in operating expenses and capital expenditures;
capital market conditions;
rating actions by Moody's, Standard & Poor's (S&P) and Fitch;
competition for new energy development opportunities;
results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;
natural disasters, acts of war or terrorism;
legal and administrative proceedings (whether civil or criminal) and settlements that influence business and profitability; and
new accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.
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.
RISK FACTORS:
The following are some important factors that could have a significant impact on the operations and financial results of IDACORP and IPC and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements:
IPC has a predominately hydroelectric generating base. Because of its heavy reliance on inexpensive hydroelectric generation, IPC's operations can be significantly affected by the weather. IPC is currently forecasting that the year 2003 will be its fourth consecutive year of below normal water conditions. When hydroelectric generation is reduced because of below normal water conditions, IPC must increase its use of more expensive thermal generation and purchased power. Although IPC generally recovers certain increased power costs through its Power Cost Adjustment (PCA), the recovery is on a deferred basis and is subject to the regulatory process.
IPC is currently involved in renewing federal licenses for certain of its hydroelectric projects. IPC currently expects new licenses for five middle Snake River region hydroelectric plants to be issued in 2003. In addition, IPC expects to file the license application in July 2003 for the Hells Canyon Complex, which provides 40 percent of IPC's total generating capacity. IPC cannot predict what conditions, if any, with respect to environmental, operating and other matters the FERC may impose in connection with the renewal of these licenses and the effect of any such conditions on IPC's operations.
IDACORP and IPC are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of, among other factors, changes in legislation and enforcement policies and additional requirements imposed in connection with the relicensing of IPC's hydroelectric projects.
IPC currently anticipates filing a general rate case with the IPUC by the end of the year 2003. The rate case is being filed as a result of capital expenditures made and increased operating costs experienced by IPC since 1993, the last rate case test year except for those capital costs associated with construction of the Milner and expansion of the Twin Falls hydroelectric projects which were included in rates in 1995. IPC cannot predict the outcome of this case or the effect on its operations if the requested rate relief is not granted.
IDACORP and IPC are subject to direct and indirect effects of terrorist threats and activities. Generation and transmission facilities, in general, have been identified as potential targets. The effects of terrorist threats and activities include, among other things, actions or responses to such actions or threats, the inability to generate, purchase or transmit power, and the increased cost and adequacy of security and insurance.
IPC and its affiliate, IE, may be subject to potential liabilities as a result of energy marketing operations. Although IE is currently winding down its energy marketing operations, certain matters have been identified that require resolution with the FERC and the IPUC. Should the FERC conclude that its regulations or rate schedules were not complied with, it has significant discretion as to the appropriate remedies, if any. The FERC's remedial authority includes the authority to require refunds, to order equitable relief, to suspend the authorization to sell wholesale power at market-based rates, and, in some instances, to impose monetary penalties. In an IPUC proceeding that has been underway since May 2001, IPC and the IPUC staff have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates since February 2001. IPC and IE do not believe that resolution of these transactions will have any adverse impact on retail customers or a material adverse effect on their ongoing operations. However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on the companies' financial statements and whether it will be material.
IDACORP, IE and IPC are subject to costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including those that may arise out of the California energy situation. Regarding the California energy situation, IDACORP, IE and IPC are involved in a number of proceedings including a complaint filed against sellers of power in California, based on California's unfair competition law, a cross-action wholesale electric antitrust case against various sellers and generators of power in California and the California refund proceeding at the FERC. Other cases which are the direct or indirect result of the energy crisis in California include efforts by certain public parties to reform or terminate contracts for the purchase of power from IE and the Northwest refund case at the FERC. It is possible that additional proceedings may be filed against or by IDACORP, IE or IPC related to the California energy crisis in the future.
IDACORP and IPC rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. Access to capital markets at a reasonable cost is determined in large part by credit quality. An inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could impact the liquidity of IDACORP and IPC and would likely increase their interest costs. It could also affect the companies' ability to implement their business plans.
The issues and associated risks and uncertainties described above are not the only ones IDACORP and IPC may face. Additional issues may arise or become material. The risks and uncertainties associated with these additional issues could impair IDACORP's and IPC's businesses in the future.
SUMMARY OF 2002 RESULTS AND 2003 OUTLOOK:
Overall Results
IDACORP's overall results show earnings per share (EPS) of $1.63, a decrease of $1.72 from 2001. IPC's EPS increased from $0.60 in 2001 to $2.24 in 2002 despite the operational impacts of continued below normal streamflow conditions on IPC's hydro system and reduced general business sales. At IE, EPS decreased significantly from $2.87 in 2001 to a current year loss of $0.39. IE's results have been significantly impacted by deteriorating credit, substantially reduced pricing spreads, and low volatility in the Western wholesale energy markets as well as the decision to wind down energy marketing operations. IDACORP's results also reflect an $8 million partial write-down of Ida-West's investment in equipment related to the proposed Garnet energy project.
Since the announcement to wind down its energy marketing operations, IE has recorded $9 million in severance expenses, non-cancelable lease liabilities and asset impairments, among other matters. IE has reduced its workforce from a peak last year of 125 to fewer than 60 employees as of December 31, 2002. Further reductions in the workforce to approximately 20 employees are expected by July 2003.
Utility operations benefited from a tax accounting method change that allowed IPC to record a $35 million tax benefit. $31 million of this benefit is attributable to 2001 and prior years.
This benefit was partially offset by expensing $12 million in lost irrigation revenues disallowed by the IPUC. IPC disagrees with the IPUC's decision to disallow recovery of the $12 million in lost irrigation revenues and has filed an appeal with the Idaho Supreme Court seeking to overturn the IPUC's decision. IPC filed its brief on January 31, 2003. It is anticipated that this case will not be decided by the Idaho Supreme Court until late 2003 or early 2004. If successful, IPC would record any amount recovered as revenue.
Hydroelectric Generation and Below Normal Water Conditions
The following table presents IPC's system generation for the last three years:
IPC relies on low-cost hydroelectric plants for a significant portion of its power supply. IPC's hydroelectric generation has decreased since 2000 as IPC has experienced three years of below normal water conditions. Under normal streamflow conditions, IPC's generation mix is 57 percent hydro and 43 percent thermal. The amount of electricity IPC is able to generate from its hydro plants depends primarily on the snowpack in the mountains above its hydro facilities, reservoir storage and streamflow conditions.
Current Snake River basin snowpack numbers suggest that streamflow conditions for 2003 will remain below normal. IPC's March 2003 accumulations were 78 percent of normal, compared to 85 percent at the same time a year earlier.
The U.S. Weather Service's River Forecast Center at this time is predicting April-through-July inflow into Brownlee Reservoir will be 3.7 million acre-feet (maf). The normal 30-year average for inflow during that time is 6.3 maf. Based on the above snowpack and forecasted inflows, IPC is expecting its fourth year of below normal water conditions. IPC currently plans to use wholesale purchases from the energy markets when necessary to meet its energy needs during 2003.
Integrated Resource Plan
On February 11, 2003, the IPUC issued Order No. 28189 that accepted and acknowledged IPC's 2002 Integrated Resource Plan (IRP), which identified IPC's options to meet potential electricity shortfalls expected by mid-2005. The accepted IRP indicated the purchase of 100 MW from the wholesale market for IPC's retail customers during June, July, November and December - the months when it is difficult for IPC to generate enough electricity to meet its customer needs. Other options identified by IPC include:
Seasonal energy exchanges with other utilities;
Obtaining firm transmission rights;
Construction of new generating resources; and
Purchasing capacity from new generating resources.
On February 24, 2003, IPC issued a formal Request for Proposals (RFP) seeking bids for the construction of up to 200 MW of additional generation to support the growing seasonal demand for electricity in IPC's service area. Notice of an intent to bid must be submitted to IPC by March 14, 2003.
Power Cost Adjustment and General Rate Relief
At December 31, 2002, the PCA deferral balance has decreased by $164 million from December 31, 2001. This decrease is attributable to a 75 percent decline in the price of wholesale electricity purchased power costs. When the new PCA year starts in May 2003, IPC expects that retail rates for most customer categories in Idaho will decrease.
The amount of PCA costs not recovered through the PCA mechanism was approximately $25 million in 2002 compared to approximately $76 million in 2001. With more normal market prices and water conditions, IPC would absorb lesser or no amounts.
While the PCA has been a valuable tool for IPC during the energy crisis and increased power supply costs in 2000 and 2001, it has not provided revenue recovery related to IPC's other costs of serving its customers such as increased operating expenses and substantial demands for infrastructure improvements. Additionally, IPC is expecting increased capital costs for the protection, mitigation and enhancement requirements of new licenses for some of its hydroelectric projects, its need for new sources of power supply and the need to continue the expansion of its transmission and distribution network.
As a result of the items mentioned above, IPC anticipates filing a general rate case with the IPUC before year-end 2003. This will be IPC's first general rate case filing since 1994. IPC anticipates the request for an increase will be substantially less than the expected PCA-related rate decrease expected in May 2003.
Legal Issues and Regulatory Matters
IDACORP, IPC and IE have been named as defendants in various legal cases during 2002. These cases continue to be reviewed on an ongoing basis. At this time, the companies believe they have meritorious defenses to all lawsuits and legal proceedings and are making a continuous effort for resolution of all outstanding matters. At the time of this filing, the companies have settled legal proceedings with Truckee-Donner Public Utility District (Truckee) without material adverse effect on their consolidated financial positions, results of operations or cash flows. The case filed by the Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) was dismissed with prejudice on January 28, 2003.
IE and IPC voluntarily contacted the FERC in September 2002 to discuss certain matters that needed to be resolved in connection with the wind down of energy marketing at IE, and the companies have provided certain documents and information to the FERC at its request. On February 26, 2003, the FERC resolved one of the matters, approving the assignment of certain wholesale power and transmission services agreements from IPC to IE.
Liquidity
IDACORP and IPC's operating cash flows in 2002 were $348 million and $366 million, respectively, driven by collections of outstanding PCA amounts, reduced power supply costs and the receipt of tax refunds. The increased cash flows were used to pay down short-term debt and redeem IPC's auction rate preferred stock.
Operating cash flow for 2003 will be supported by ongoing collections of past PCA deferrals and continued cash collections during the wind down of the energy marketing business. IDACORP has budgeted approximately $162 million for capital expenditures in 2003 of which $150 million will be for capital expenditures at IPC. Approximately 60 percent of the budgeted amounts at IPC are dedicated to its delivery system, 30 percent is for support of its power supply and relicensing efforts and 10 percent is for general plant and administrative expenditures.
Pension expense is expected to increase from approximately $0 in 2002 to approximately $7 million in 2003. Of this amount, approximately 70-75 percent will impact IPC's operation and maintenance expense. At the end of 2002, the projected benefit obligation exceeded pension assets by approximately $12 million. Based on current estimates, cash contributions in 2003 are not expected.
IDACORP has committed to continue to reduce its reliance on short-term borrowings during 2003. IDACORP is reviewing options that may include refinancing debt at IFS and IPC.
IDACORP and IPC have credit facilities that expire in March 2003. Accordingly, both companies expect to have renewed these facilities by the end of first quarter 2003.
The amount and timing of dividends payable on IDACORP's common stock are within the sole discretion of IDACORP's Board of Directors. The Board of Directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP's financial position and results of operations, legislative and regulatory developments affecting the electric utility industry in general and IPC in particular, competitive conditions and any other factors the Board of Directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily IPC.
IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC paid dividends to IDACORP of $70 million annually in 2002, 2001 and 2000.
Financing Activities
During the fourth quarter of 2002, IPC issued $200 million of First Mortgage Bonds in two series. The proceeds were used to pay down short-term debt at IPC.
IPC is in the process of establishing a $300 million shelf registration to facilitate future financing needs.
At this time IDACORP does not anticipate issuing equity securities during the balance of 2003 other than through the normal course of its various stock plans.
CRITICAL ACCOUNTING POLICIES:
IDACORP and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates, including those related to rate regulation, mark-to-market accounting on energy trading contracts, contingencies, litigation, income taxes, restructuring costs, benefit costs and bad debts. These estimates are based on historical experience and on various other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, will make adjustments when facts and circumstances dictate.
IDACORP and IPC believe the following critical accounting policies are important to the portrayal of their financial condition and results of operations and require management's most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.
Accounting for Rate Regulation
A regulated company must satisfy the following conditions in order to apply the accounting policies and practices of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," an independent regulator must set rates; the regulator must set the rates to cover specific costs of delivering service; and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. SFAS 71 requires companies that meet the above conditions to reflect the impact of regulatory decisions in its consolidated financial statements and requires that certain costs be deferred as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities and amortized to the income statement as rates to customers are reduced.
IPC follows SFAS 71, and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating IPC. The primary result of this policy is that IPC has deferred $499 million of regulatory assets and $114 million of regulatory liabilities at December 31, 2002. While IPC expects to fully recover these regulatory assets or return these regulatory liabilities, such recovery is subject to final review by the regulatory entities.
If IPC should determine in the future that it no longer meets the criteria for continued application of SFAS 71, it could be required to write off its regulatory assets and liabilities unless regulators specify some other means of recovery or refund. IPC intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, IPC cannot predict whether it will be successful.
Mark-to-Market Accounting for Energy Marketing Contracts
IE values its energy trading contracts using mark-to-market accounting under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," and Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." This accounting requires IE to consider several factors, including current relevant market prices, market depth and liquidity, potential model error, and expected credit losses at the counterparty level. Due to the volatility of energy markets and certain model assumptions, changes in market conditions could substantially change the amounts of gains or losses ultimately realized in settlement of the contracts.
Marking a contract to market consists of reevaluating the market value of the entire term of the contract at each reporting period and reflecting the resulting gain or loss of value in earnings for the period. This change in value represents the difference between the contract price and the current market value of the contract. The change in market value of the contract could result in large gains or losses recorded in earnings at each subsequent reporting period unless there are off-setting changes in value of off-setting contracts. The gain or loss in income generated from the change in market value of the energy trading contracts is a non-cash event. If these contracts are held to maturity, the cash flow from the contracts, and their off-setting contracts, is realized over the life of the contract.
When determining the fair value of marketing and trading contracts, IE uses actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices, IE uses (when available) prices provided by other external sources. When prices from external sources are not available, IE determines prices by using internal pricing models that incorporate available current and historical pricing information. Finally, the fair market value of contracts is adjusted for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level.
The following table details the gross margin booked from marketing operations over the last three years:
At year-end 2002, 63 percent of the credit exposure related to IE's unrealized positions was with investment grade counterparties, two percent was with non-investment grade counterparties and the remaining 35 percent was with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives.
The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2001 and year-end 2002 is explained as follows:
The fair value of energy marketing and trading contracts is an accounting estimate based on reasonable assumptions related to interest rates, energy prices and price volatility. Different assumptions regarding these variables could result in a change to the net fair value of energy marketing and trading contracts. The following table shows the estimated adverse change to the reported fair value of energy marketing and trading contracts for defined adverse moves associated with the key assumptions incorporated into this estimate:
The following table presents the net fair value of contracts outstanding at December 31, 2002, disaggregated by source of fair value and maturity of contracts:
Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental and Bloomberg. The time horizon is January 2003 through December 2007. Products include physical, financial, swap, interest rate, index and basis for both natural gas and heavy load power.
Prices provided by other external sources are quoted periodically by brokers and trading exchanges such as TFS, APB, Prebon, Intercontinental and Bloomberg. The time horizon is January 2003 through December 2010. Products include physical, financial, swap, index and basis for both natural gas and heavy and light load power.
Prices derived from models and other valuation methods incorporate available current and historical pricing information. The time horizon is January 2003 through December 2007. Products include transmission, options, and ancillary services related to heavy and light load power.
Pension Expense
IPC maintains a qualified defined benefit pension plan (Qualified Plan) covering most employees and an unfunded nonqualified deferred compensation plan for certain senior management employees and directors. Pension income (expense) for these plans totaled ($4 million), $4 million and $7 million for the three years ended December 31, 2002, 2001 and 2000, respectively, including amounts allocated to capitalized labor costs.
Pension expense is dependent on several assumptions used in the actuarial valuation of the plan. The primary assumptions are the long-term return on plan assets and the discount rate. Annually, these assumptions are reviewed in light of changes in market conditions, trends, and future expectations. These assumptions and the results of actuarial valuations are discussed in Note 10 to the Consolidated Financial Statements.
If these assumptions had been different, the net amounts of pension expense recorded could have varied significantly. Lowering the expected long-term rate of return on the Qualified Plan assets by 0.5 percent (from 9.0 percent to 8.5 percent) would have increased pension expense for 2002 by approximately $1.6 million. Lowering the discount rate by 0.5 percent would have increased pension expense for 2002 by approximately $1.5 million.
The value of the Qualified Plan assets has decreased from $326 million at December 31, 2001 to $283 million at December 31, 2002. The investment performance returns and declining discount rates have changed the funded status of the Qualified Plan, net of benefit obligations, from being overfunded by $53 million at December 31, 2001 to being underfunded by $12 million at December 31, 2002. Despite the recent reductions in the funded status of the Qualified Plan, IPC believes that, based on current actuarial assumptions, it will not be required to make any cash contributions to the Qualified Plan in 2003.
Contingent Liabilities
A number of unresolved issues related to regulatory, legal and tax matters are discussed throughout the MD&A. Contingent liabilities are provided for in accordance with SFAS 5, "Accounting for Contingencies." According to SFAS 5, an estimated loss from a loss contingency shall be charged to income if (a) it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. Disclosure in the notes to the financial statements is required for loss contingencies not meeting both those conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until earned.
For all such significant matters, best estimates of the ultimate resolution have been made, and, if the recognition criteria of SFAS 5 have been met, reserves have been recorded. The final outcome of these matters could vary significantly from the amounts that have been included in the current financial statements.
RESULTS OF OPERATIONS:
In this section IDACORP's earnings and the factors that affected them are discussed, beginning with a general overview followed by a more detailed discussion of the electric utility and energy marketing activities for the years ended December 31, 2002, 2001 and 2000.
EPS from utility operations increased for the year ended December 31, 2002. Major changes occurring at the utility caused the following fluctuations in EPS:
Net power supply costs absorbed by the utility decreased $51 million, increasing EPS $0.82.
A change to the utility's tax accounting method for capitalized overhead costs created a tax benefit of $35 million or a $0.92 increase to EPS.
Lost revenue of $12 million was expensed during third quarter 2002, after the utility was denied its request to recover lost revenue from the 2001 Irrigation Load Reduction Program. This amount compares to $10 million in disallowed PCA costs expensed during 2001.
High wholesale energy prices and below normal water conditions had a negative effect on utility operations from 2000 to 2001. Of the $1.37 decrease from 2000, $0.70 per share is attributable to increases in power supply expenses absorbed by IPC and $0.18 per share is due to the write-off of amounts disallowed in IPC's 2001 PCA. Additional increases in operating expenses for maintenance, depreciation, interest and customer expenses decreased earnings by approximately $0.34 per share.
EPS from energy marketing decreased $3.26 per share in 2002 after increasing $1.29 per share in 2001. In spite of a 13 percent increase in settled electricity volume during 2002, earnings decreased driven by a sharp decline in regional prices, price spreads and volatility, combined with the decreasing number of creditworthy counterparties. In addition, the decision to wind down energy marketing and trading at IE has resulted in significantly reduced earnings from this segment. Compounding this decline in earnings is $9 million of restructuring and other costs associated with the wind down of energy marketing. The strong performance in 2001 was driven primarily by increased price volatility and regional price spreads and a 49 percent increase in settled electricity sales volume.
Combined EPS from IDACORP's other subsidiaries decreased in both 2002 and 2001, primarily due to transactions at Ida-West. In 2002, Ida-West recorded an $8 million impairment of its Garnet fixed asset, reducing EPS by $0.13. In 2000, Ida-West recorded a $14 million gain on the sale of the Hermiston Power Project, which contributed approximately $0.22 per share.
Utility Operations
This section discusses IPC's utility operations, which are subject to regulation by, among others, the state public utility commissions of Idaho and Oregon and by the FERC.
General Business Revenue: The following table presents IPC's general business revenues and MWh sales for the last three years:
As mentioned above, our general business revenue is dependent on many factors, including the number of customers we serve, the rates we charge, and weather conditions.
2002 vs. 2001: The following factors influenced the 19 percent increase in general business revenue:
Rate increases due to the annual PCA resulted in increased revenues of approximately $94 million. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs."
Customer growth in IPC's service territory increased approximately two percent, resulting in a $10 million increase in revenues.
In 2001 many irrigation customers participated in a program to decrease their usage. This program was not in effect during 2002, resulting in increased sales to irrigation customers of $20 million.
FMC/Astaris, previously IPC's largest volume customer, closed its Pocatello manufacturing plant late in 2001. However, based on a take or pay contract with FMC/Astaris which requires payment for power regardless of delivery, IPC will continue to receive payments from FMC/Astaris through March 2003. Because of this, revenues from FMC/Astaris changed minimally, despite the significant decrease in MWh sold.
2001 vs. 2000: The following factors influenced the 15 percent increase in general business revenue:
Increased average rates, resulting from the PCA, increased revenue $137 million. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs."
A 2.5 percent increase in general business customers increased revenue $16 million.
Conservation programs, including irrigation and large customer buybacks, and other usage factors, decreased energy consumption, reducing revenues $67 million.
Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy.
2002 vs. 2001: In 2002, off-system sales decreased due to a 13 percent decrease in volumes sold and a 71 percent decrease in wholesale electricity prices.
2001 vs. 2000: Off-system sales decreased due principally to a 47 percent decrease in volume sold, a result of poor hydro generating conditions. The volume decrease was partially offset by an 81 percent increase in price per MWh.
Purchased power:
2002 vs. 2001: During 2002, purchased power costs decreased primarily due to a 75 percent reduction in average wholesale electricity prices. Load reduction payments also included in purchased power have decreased $103 million due to expiration of the Irrigation Load Reduction Program and changes to the FMC/Astaris Voluntary Load Reduction Agreement. See "REGULATORY ISSUES - FMC/Astaris Settlement Agreement."
2001 vs. 2000: Purchased power expenses increased in 2001. Contributing to these results are a number of factors, including wholesale market conditions, and $154 million of irrigation and FMC/Astaris load reduction program costs.
Fuel expense: The following table presents IPC's fuel expenses and generation at its thermal generating plants:
2002 vs. 2001: Fuel expenses during 2002 increased due to a nine percent increase in average coal prices partially offset by a four percent decrease in thermal generation.
2001 vs. 2000: Fuel expenses increased in 2001, despite decreased generation. Average coal prices increased, and the Danskin 90-MW gas-fired plant went on-line in September 2001.
PCA: The PCA expense component is related to IPC's PCA regulatory mechanism. In 2002, actual power supply costs have exceeded those anticipated in the forecast. Below normal water conditions are still impacting power supply costs even though power supply prices are significantly lower than 2001. In 2001, actual power supply costs were significantly greater than forecasted, resulting in a large PCA credit, which is now being recovered in rates (as revenues) and the deferred balance is being amortized as PCA expense. FMC/Astaris and Irrigation Load Reduction Program cost deferrals also affect the PCA. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs."
The following table presents the components of PCA expense:
Energy Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations, stating that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce at its Boise operations by approximately 50 percent. On November 5, 2002, IDACORP announced that it was terminating further evaluation of growth opportunities in the mid-stream natural gas markets, and stated that IE would close its Denver office by year-end 2002, and because of its link to the natural gas platform, would shut down its natural gas trading operation in Houston by March 2003. The announcement concluded that IE's continued wind down of its energy marketing operations would result in additional workforce reductions at IE's Boise operations through mid-2003. Since the June 21, 2002 announcement, IE has reduced its workforce by over 60 percent and will continue to reduce its workforce as contractual obligations terminate.
IE recorded a restructuring charge in the fourth quarter of 2002 of $7 million and additional charges related to exiting the business of $1 million for a total of $8 million. For the year, the charges were $9 million and relate to, among other matters, severance charges, non-cancelable lease liabilities and asset impairments.
In connection with the wind down of energy marketing, matters have been identified that require resolution with the FERC or the IPUC. One matter that required resolution with the FERC included the assignment of IPC's power marketing contracts to IE without obtaining the required prior approval of the FERC. On February 26, 2003, the FERC issued an order approving the assignment of certain wholesale power and transmission services agreements from IPC to IE. The IPUC matters include a proceeding that has been
underway since May 2001 where IPC and the IPUC staff have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates.
These matters are discussed in more detail in Note 13 to the Consolidated Financial Statements.
IE reported a $24 million operating loss in 2002 compared to $177 million of operating income in 2001. Gross margin for 2002 was $4 million, which included $66 million in unrealized losses related to the settlement, during 2002, of outstanding positions at year end 2001 and the change in value of IE's forward positions at year end 2002. On a cumulative basis, IE anticipates that approximately 40 percent of these unrealized forward positions recorded at year end 2002 will be settled by the end of 2003, 58 percent settled by the end of 2004 and 71 percent settled by the end of 2005. All forward positions at December 31, 2002 should be settled within eight years. Changes in market conditions in future periods could substantially change the amounts of gain or loss ultimately realized upon settlement of the contracts.
Revenues: IDACORP elected in third quarter 2002 to change its presentation of energy trading activities from gross to net presentation, as discussed in Note 1 to the Consolidated Financial Statements. Prior periods have been reclassified to conform to current presentation. Operating revenues include revenues from the sale of electricity and gas netted against the cost of purchased power and natural gas. All financial transactions and unrealized income are presented on a net basis as operating revenue. Operating expenses include general and administrative expenses, bad debt reserves, transmission expenses and broker fees. IDACORP's net financial position and results of operations were not affected by this change in presentation.
The following table presents IE's energy marketing revenues and volumes for the last three years:
The decline in revenues between 2001 and 2002 was driven by a sharp decline in regional prices, price spreads and volatility, combined with the decreasing number of creditworthy counterparties. In addition, the decision to wind down energy marketing at IE has resulted in significantly reduced revenue from this segment. IE's growth in revenue between 2000 and 2001 was due to an increase in wholesale electricity prices, electricity price volatility and growth in settled physical electricity volumes. IE anticipates revenues in 2003 to continue to decline as IE continues to complete its obligations under existing contracts and wind down its business.
Selling, General and Administrative Expenses: Total selling, general and administrative (SG&A) expenses decreased $38 million in 2002 due primarily to decreased allowance for bad debt and compensation expense. Allowance for bad debt decreased in 2002 due to unusually high bad debt expense in 2001 associated with reserves related to trading activities conducted with California entities in 2000. Compensation expense has declined due to a reduction in profit related incentives and a reduction in workforce related to the wind down of operations.
SG&A expense in 2001 increased $15 million. This was attributed to a rise in allowance for bad debt associated with reserves related to trading activities conducted with California entities in 2000 and an increase in compensation driven by an increase in the workforce and profit related incentives.
Other Income and Expenses
IDACORP's other income (loss) decreased $30 million as compared to 2001. The primary reasons for this decrease are an $8 million partial write down on equipment related to the Garnet project in fourth quarter 2002 at Ida-West and a $5 million decrease attributed to early redemption of outstanding bonds held by Ida-West recognized as a gain in 2001. The early redemption of these outstanding bonds contributed to a $2 million decrease in Ida-West's 2002 interest income. IE recognized a $2 million loss on property impairment related to the wind down of IE's energy marketing activities. A $3 million loss was recorded in 2002 by IPC related to its available-for-sale securities. IPC's interest income decreased $3 million due to the decreased PCA balance as compared to 2001.
Other income decreased $7 million in 2001 as compared to 2000, due primarily to the sale in 2000 of Ida-West's interest in the Hermiston Power Project, a 536 MW, gas-fired cogeneration project to be located near Hermiston, Oregon. Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993. A pre-tax gain of $14 million was recorded on this transaction in 2000. This decrease was partially offset by a $5 million gain recognized in 2001 related to the early redemption by the Friant Power Authority of outstanding bonds held by Ida-West.
Interest Expense and Other: Interest expense and other expense decreased $7 million in 2002 and increased $9 million in 2001. The decrease in 2002 is due primarily to reductions in variable interest rates and average outstanding debt. The increase in 2001 is predominantly the result of higher short-term debt balances to finance power purchased for IPC's system, partially offset by significant decreases in borrowing rates. IDACORP's average short-term debt in 2002 was $173 million, compared to $232 million in 2001.
Tax Accounting Method Change
During the third quarter of 2002, IDACORP filed its 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs. The former method allocated such costs primarily to construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.
The effect of the tax accounting method change has been recorded as a decrease to income tax expense for the year ended December 31, 2002 of $35 million, of which $31 million is attributable to 2001 and prior tax years, and $4 million is attributable to the 2002 tax year. The decrease to tax expense is a result of deductions on the applicable tax returns of costs that were capitalized into fixed assets for financial reporting purposes. Deferred income tax expense has not been provided because the prescribed regulatory accounting method does not allow for inclusion of such deferred tax expense in current rates. Regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.
Status of Audit Proceedings
IPC settled income tax deficiencies related to its partnership investment in the Bridger Coal Company, covering the years 1991 through 1998. The settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.
Federal income tax returns for years through 1997 have been examined by the Internal Revenue Service and substantially all issues have been settled. Management believes that adequate provision for income taxes has been made for the open years 1998 and after and for any unsettled issues prior to 1998.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Cash Flow
IDACORP's and IPC's operating cash flows in 2002 were $348 million and $366 million, respectively, driven by collections of outstanding PCA amounts, reduced power supply costs and the receipt of tax refunds. The increased cash flows were used to pay down short-term debt and redeem IPC's auction rate preferred stock.
The tax refunds relate to net operating loss carrybacks associated with IPC's 2001 power supply costs and the tax accounting method change for capitalized overhead costs. Estimated tax payments offset these refunds.
Contractual Cash Obligations
The following table presents IDACORP's total contractual cash obligations in the respective periods in which they are due:
Credit Ratings
On September 10, 2002, Moody's changed its rating outlook for IPC to negative from stable. Moody's stated that the negative rating outlook reflects uncertainties relating to potential effects from the FERC-related matters associated with the wind down of the energy marketing business at IE, certain affiliated transactions and the splitting of IE into a separate subsidiary.
Access to capital markets at a reasonable cost is determined in large part by credit quality. The following outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities:
These security ratings reflect the views of the rating agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
Some collateral agreements in place between IE and its counterparties include provisions requiring additional margining in the event of a credit rating downgrade. In general, credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IDACORP. A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact on the liquidity of IDACORP. IDACORP believes its existing credit facilities are adequate to fund these potential liquidity requirements.
Working Capital
The significant changes in working capital that are not attributed to normal business activity and timing are discussed below.
Due to the wind down of the energy marketing business, IE's customer receivables have decreased $25 million, accounts payable have decreased $95 million and other liabilities have decreased $29 million.
The changes in "regulatory assets - current" and "derivative liabilities - current" are due to adoption of Financial Accounting Standards Board (FASB) Derivative Implementation Group Implementation Issue C-15, "Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity." This Implementation Issue allows contracts subject to book-outs at electric utilities to qualify for the normal purchase and sales exception in SFAS 133. IPC completed an evaluation of its booked-out contracts and determined that contracts previously classified as derivatives were exempt.
The increase in taxes accrued is primarily due to estimated taxes payable at year-end 2002, plus the receipt of $90 million in cash refunds related to net operating loss carrybacks associated with IPC's 2001 power supply costs and IPC's tax accounting method change for capitalized overhead costs.
Energy marketing assets and liabilities reflect the fair value of energy marketing contracts as of the reporting date. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The decreases in the net energy marketing assets and liabilities from 2001 to 2002 are primarily a reflection of the wind down of the energy marketing business, significantly reducing the number of forward deals that remain part of the portfolio. Also contributing to the reduction are lower market prices at December 31, 2002 than in the prior year.
Cash received from energy trading counterparties serves as collateral against open positions on energy related contracts and is reported in cash and cash equivalents. The resultant liability is recorded as a reduction to the energy marketing asset generated by the open position. Regarding the use of posted collateral, the margining agreements provide "...the right to: (i) sell, pledge, rehypothecate, assign, invest, use, commingle or otherwise dispose of, or otherwise use in its business any Posted collateral it holds..." as long as IDACORP maintains a credit rating of at least BBB- (S&P) or Baa3 (Moody's). IDACORP has continued to maintain a credit rating above this minimum and has no restrictions on the use of collateral funds.
Capital Requirements
IDACORP capital expenditures are expected to total $908 million from 2003 through 2005. This amount includes $565 million for IPC construction expenditures, excluding Allowance for Funds Used During Construction (AFDC), $190 million for IPC long-term debt maturities and $34 million for other IPC capital expenditures. Over the next three years internally generated cash and debt issuances are expected to provide the majority of the funds needed to meet IDACORP's capital requirements. Internally generated cash is expected to provide 97 percent in 2003 and an average of 76 percent in 2004 and 2005.
IPC has no nuclear involvement and its future construction plans do not include development of any nuclear generation. IPC's capital expenditures are primarily for maintaining current infrastructures and meeting anticipated electricity demands.
IFS's capital expenditures are primarily for additional investments in affordable housing projects.
The above table does not include IDACORP's future investment relating to research and development at its fuel cell subsidiary, IdaTech.
Based upon present environmental laws and regulations, IPC estimates its 2003 capital expenditures for environmental matters, excluding AFDC, will total $27 million. Studies and measures related to environmental concerns at IPC's hydro facilities account for $23 million and investments in environmental equipment and facilities at the thermal plants account for $4 million. From 2004 through 2005, environmental-related capital expenditures, excluding AFDC, are estimated to be $32 million. Anticipated expenses related to IPC's hydro facilities account for $25 million and thermal plant expenses are expected to total $7 million.
Various options that may be available to meet the future energy requirements of its customers include efficiency improvements on IPC's generation, transmission and distribution systems, purchased power and exchange agreements with other utilities or other power suppliers. IPC will pursue the projects that best meet its future energy needs.
The above estimates are subject to constant revision in light of changing economic, regulatory and environmental factors and patterns of conservation.
Financing Programs
IDACORP's consolidated capital structure fluctuated slightly during the three-year period, with common equity ending at 46 percent, preferred stock of IPC at three percent, and long-term debt at 51 percent at December 31, 2002.
Credit facilities: IPC has a $200 million facility that expires March 25, 2003. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amount supported by the bank credit facilities. At December 31, 2002, IPC had regulatory authority to incur up to $350 million of short-term indebtedness.
IDACORP has a $350 million facility that expires on March 25, 2003 and a $140 million facility that expires on March 26, 2005. Under these facilities IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities.
IDACORP and IPC plan to renew their credit facilities that expire in March 2003. IDACORP plans to replace its current $350 million facility with a 364-day facility, but at a reduced amount resulting from lower liquidity requirements at IE. IPC plans to replace its current $200 million facility with a similar sized facility.
Short-term financings: At December 31, 2002, IPC's short-term borrowing consisted of $11 million of commercial paper, compared to $282 million at December 31, 2001, consisting of $100 million of floating rate notes and $182 million of commercial paper. The increase in 2001 was primarily a result of unrecovered power supply expenditures. IPC repaid $100 million of floating rate notes in September 2002 using short-term borrowings from IDACORP. This $100 million inter-company debt was subsequently repaid with IPC first mortgage bonds issued in November 2002. At December 31, 2002, IDACORP's short-term borrowing totaled $166 million, compared to $81 million at December 31, 2001.
Long-term financings: IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2002, none had been issued.
On March 23, 2000, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. On December 1, 2000, IPC issued $80 million of Secured Medium-Term Notes, Series C, 7.38% Series due 2007. Proceeds were used in January 2001 for the early redemption of $75 million of First Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued $120 million of Secured Medium-Term Notes, Series C, 6.60% Series due 2011 with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. No amounts remain to be issued on this shelf registration statement.
On August 16, 2001, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. On November 15, 2002, IPC issued $200 million of secured medium-term notes. This issuance of medium-term notes was divided into two series. The first was $100 million First Mortgage Bonds 4.75% Series due 2012 and the second was $100 million First Mortgage Bonds 6.00% Series due 2032. Proceeds were used to pay down IPC short-term borrowings. IPC plans to file a new shelf registration statement for first mortgage bonds (including medium-term notes), unsecured debt and preferred stock in the first quarter of 2003.
In August 2001, $25 million of First Mortgage Bonds 9.52% Series due 2031 were redeemed early. Also, in March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.
IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.
IPC has $80 million First Mortgage Bonds 6.40% Series due April 28, 2003 and has the ability to redeem another $80 million first mortgage bonds. Also in 2003, IPC is considering refunding early $50 million Humboldt County, Nevada, Pollution Control Revenue Bonds 8.30% due 2014.
Under the terms of the Indenture relating to IPC's First Mortgage Bonds, net earnings must be at least two times the annual interest on all bonds and other equal or senior debt. For the twelve months ended December 31, 2002, net earnings were 4.16 times.
In 2002, IDACORP considered the issuance of common stock or equity linked securities. In light of the decision to wind down IE's wholesale energy marketing function and reviewing options to balance its capital structure, IDACORP does not anticipate issuing new common equity or equity linked securities during 2003 except for common stock issued for the Dividend Reinvestment Plan, the Employee Savings Plan, the Restricted Stock Plan and the IDACORP Long-Term Incentive and Compensation Plan.
LEGAL AND ENVIRONMENTAL ISSUES:
Legal and Other Proceedings
California Energy Situation: On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the California Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, IE believes its exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review. The latter--more than 60--have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations. The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation and although the California Parties (the California Attorney General, other state agencies and the California Investor Owned Utilities) have requested specific procedures to implement that requirement, the FERC has not yet acted on that request.
On November 20, 2002, the FERC issued an order allowing the parties to the California refund proceeding to conduct discovery for one hundred days into market manipulation by various sellers during the Western power crises of 2000 and 2001. At the conclusion of the discovery period parties alleging market manipulation are to submit their claims to the FERC and parties have until March 20, 2003 to submit evidence or comments in response, including assertions that cross-examination is warranted. On March 3, 2003, a group of California parties, including the California Attorney General, the California Public Utilities Commission, the California Electricity Oversight Board, SCE and PG&E, filed materials with the FERC claiming that wholesale power suppliers manipulated the California market during 2000-2001. They seek approximately $8 billion in refunds for the state's ratepayers. A number of wholesale power suppliers were named in the filings, including IDACORP and IPC. IDACORP and IPC intend to vigorously defend in this matter, but they are unable to predict the outcome of this proceeding. See Note 8 to the Consolidated Financial Statements.
Overton Power District No. 5: IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5 (Overton), a Nevada electric improvement district, based on Overton's breach of its power contracts with IE. The July contract provided for Overton to purchase 40 MW of electrical energy per hour from IE at $88.50 per MWh, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.
IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim claiming, among other things, that IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in the amount to be proved at trial. Overton also asserts that the contract is unenforceable or subject to rescission. IE believes Overton's assertions are without merit. IE and Overton filed cross motions for summary judgment that have been denied by the Court. The parties continue with discovery in the lawsuit. Trial is scheduled to commence on May 5, 2003.
IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain and IE has not yet completed discovery, IE continues to believe that it should prevail on the merits. At December 31, 2002, IE had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. The recoverability of the asset is subject to Overton's willingness and ability to raise its rates as provided for in the contract.
Other Legal Proceedings: IDACORP, IPC and/or IE are involved in various lawsuits and legal proceedings, discussed above and in detail in Note 8 to the Consolidated Financial Statements. The companies believe they have meritorious defenses to all lawsuits and legal proceedings where they have been named as defendants. Resolution of any of these matters will take time, and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters. Litigation with Truckee was settled on January 3, 2003 and the case filed by Grays Harbor was dismissed with prejudice on January 28, 2003. See Note 8 to the Consolidated Financial Statements.
FERC Investigations Regarding Trading Practices: In a series of requests for information ending on May 8, 2002 the FERC issued a data request to all sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001. The request required IPC and IE to respond in the form of an affidavit to inquiries respecting various trading practices that the FERC identified in its fact-finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000. IPC and IE filed the various responses sought by the FERC. The May 2002 response indicated that although they did export energy from the CalPX outside of California during the period 2000-2001, they did not engage in any impermissible trading practice described in the Enron memoranda and identified by the FERC. The energy purchased within and exported out of California was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction. The companies denied engaging in the other ten practices identified by the FERC. IPC and IE filed additional responses with the FERC on May 31 and June 5, 2002. In the May 31 response, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price. In the June 5 response, where the data request was directed to all sellers of natural gas in the Western Systems Coordinating Council and/or Texas during the years 2000-2001, the companies denied engaging in the practice referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of natural gas together with a simultaneous purchase of the same product at the same price.
U.S. Commodity Futures Trading Commission Investigations Regarding Trading Practices: On October 2, 2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to IPC requesting, among other things, all records related to all natural gas and electricity trades by IPC involving "round trip trades", also known as "wash trades" or "sell/buyback trades" including, but not limited to those made outside the Western Systems Coordinating Council region. The subpoena applies to both IE and IPC. As discussed above, on May 22, 2002, both IE and IPC responded to a similar request from the FERC stating that they did not engage in "round trip" or "wash" trades. By letter from the CFTC dated October 7, 2002, the Division of Enforcement agreed to hold in abeyance until a later date all items requested in the subpoena with the exception of one paragraph which related to three trades on a certain date with a specific party. The companies provided the requested information.
On January 14, 2003, IPC received a request from the CFTC, pursuant to the October 2002 subpoena, for documents related to "round trip" or "wash trades" and information supplied to energy industry publications. The request applies to both IPC and IE. The companies stated in their response to the CFTC that they did not engage in any "round trip" or "wash trade" transactions and that they believe the only information provided to energy industry publications was actual transaction data. The companies have provided the requested information.
Environmental Issues
Salmon Recovery Plan: IPC is continuing to monitor regional efforts to develop a comprehensive and scientifically credible plan to ensure the long-term survival of anadromous fish runs on the Columbia and lower Snake Rivers.
In November of 1991, the National Marine Fisheries Service (NMFS) listed the Snake River Sockeye Salmon as endangered under the Endangered Species Act (ESA). Subsequently, in April 1992, NMFS listed the Snake River Fall Chinook and the Snake River Spring/Summer Chinook as threatened under the ESA. Only the Snake River Fall Chinook inhabit the Snake River in the vicinity of IPC's three-dam Hells Canyon Complex (HCC). These listings have not had any major effects on IPC's operations. In 1991, IPC voluntarily initiated a Fall Chinook Interim Recovery Plan and Study intended to address concerns relative to Fall Chinook spawning immediately below Hells Canyon Dam. Since the inception of that plan, IPC has been managing releases from the HCC during the Fall Chinook spawning season to provide stable conditions for spawning Fall Chinook below Hells Canyon Dam. These conditions are maintained through fry emergence in the spring. In connection with the relicensing of the HCC, IPC is engaged in ongoing discussions with the FERC and NMFS relative to ESA issues associated with the HCC.
In December 2000, NMFS issued a final Biological Opinion (BiOp) on the operation of the Federal Columbia River Power System (FCRPS). This BiOp resulted from ESA Section 7 consultation on the operations of the federal projects operated by the U.S. Army Corps of Engineers and U.S. Bureau of Reclamation (BOR) on the lower Snake and Columbia Rivers. It did not relate to the operations of IPC's HCC and did not call for any changes in the operations of the HCC.
In May of 2001, NMFS issued a final BiOp on the operations of the BOR projects in the Snake River basin above the HCC. This BiOp was interim in nature, expiring in March 2002. NMFS and the BOR are currently negotiating an extension of this BiOp for subsequent years' operations.
Portions of the 2000 FCRPS BiOp and the 2001 BOR BiOp provide for the acquisition of water from Idaho by the BOR in order to provide augmentation flows to assist with the downstream migration of ESA listed anadromous fish through the lower Snake River FCRPS projects. For the past several years, the BOR has been leasing water from willing lessors in Idaho in an effort to provide the augmentation flows. In connection with these flow augmentation efforts, IPC has been cooperating with the federal agencies by moving and shaping water acquired by the BOR through the HCC. In the past, IPC has been reimbursed for any energy losses incurred as a result of this cooperation through an agreement with the Bonneville Power Administration (BPA). While this agreement expired in April of 2001, IPC has advised federal interests of its willingness to continue to assist with the movement and shaping of federal flow augmentation water provided any adverse impact to its customers is satisfactorily addressed.
The federal interests determined not to reimburse IPC and IPC did not assist with the movement and shaping of federal flow augmentation water during 2001 or 2002.
Threatened and Endangered Snails: In December 1992, the U.S. Fish and Wildlife Service (USFWS) listed five species of snails that inhabit the middle Snake River as threatened or endangered species under the ESA. In 1995, in preparation for the FERC relicensing of certain of IPC's hydropower projects, IPC obtained a permit from the USFWS to study the listed snails. Since that date, IPC has been collecting field data and conducting studies in an effort to determine the status of the listed snails and how they may be affected by a variety of factors, including hydropower production, water quality and irrigation practices.
IPC is currently involved in renewing five federal licenses for hydroelectric projects in the middle Snake River region. Those projects include the Upper Salmon Falls, Lower Salmon Falls, Bliss, Shoshone Falls (collectively called the Mid-Snake projects) and the C. J. Strike projects. The potential impact of the operation of these projects on the five ESA listed snails has raised some issues in the relicensing processes before the FERC. Section 7 of the ESA requires that the FERC consult with the USFWS on any proposed federal action, such as the relicensing of IPC's projects, that may affect a species listed as threatened or endangered under the ESA. On January 16, 2002, the FERC requested that the USFWS engage in Section 7 consultation on the proposed relicensing of the Mid-Snake projects with regard to the ESA listed snails. If the FERC determines that operation of IPC's Mid-Snake projects adversely affects a listed snail, they may impose operating constraints that could result in loss of peaking capacity at the projects. The cost of replacing this peaking capacity will vary depending upon market conditions and the replacement option selected.
Based upon the studies initiated by IPC in 1995, in July and October of 2002 IPC, in cooperation with the State of Idaho, filed petitions with the USFWS to remove the Bliss Rapids snail and Idaho springsnail from the federal list of threatened and endangered wildlife. Because of the pending relicensing proceedings at the FERC and the ESA consultation between the FERC and USFWS on the potential effect of project operations on ESA listed snails, IPC submitted the petitions, and the studies upon which they were based, to the FERC for inclusion in the Mid-Snake and C J Strike relicensing proceedings.
On December 13, 2002, because of inconsistencies discovered in field data collected by IPC since 1995, the macro invertebrate database into which the field data was entered and the use of that database in the preparation of the studies used to support the pending petitions, IPC notified the USFWS and the FERC that it was withdrawing the petitions. IPC has retained an independent scientist to review the procedures used to collect the field data, the creation of the database, the database itself and its use in preparing the snail studies. IPC has advised the FERC that it expects this independent review will be completed by March 30, 2003 and has asked that the FERC withhold any action on the pending ESA Section 7 consultation until the independent review is complete. The USFWS has also requested that the consultation be extended until the completion of the independent review process.
Environmental Regulation Costs: IPC anticipates $12 million in annual operating costs for environmental facilities during 2003. Hydro facility expenses account for $8 million of this total and $4 million is related to thermal plant operating expenses. From 2004 through 2005, total environmental related operating costs are estimated to be $25 million. Anticipated expenses related to the hydro facilities account for $17 million and thermal plant expenses are expected to total $8 million during this period.
REGULATORY ISSUES:
Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at December 31, 2002 and 2001:
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which take effect in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment.
So far in the 2002-2003 PCA rate year, actual power supply costs have exceeded those anticipated in the forecast. Below normal water conditions are still impacting power supply costs even though power supply prices are significantly lower. In addition, an Irrigation Load Reduction Program was completed in the 2001-2002 PCA rate year and the FMC/Astaris Voluntary Load Reduction costs have decreased, both reducing the PCA regulatory account balance from $290 million as of December 31, 2001 to $126 million as of December 31, 2002.
On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs, consisting of:
$209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002.
$28 million of excess power supply costs forecasted for the period April 2002 through March 2003.
$18 million of unamortized costs previously approved for recovery beginning October 1, 2001. The amount authorized in October 2001 totaled $49 million. This order spreads the remaining October 2001 rate increase, which would have ended in September 2002, through May 2003.
The order also:
Denied recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program, and $2 million of other costs IPC sought to recover.
Deferred recovery of $12 million of costs related to irrigation and small general service customers. In June 2002, the IPUC issued Order No. 29065 deferring an additional $4 million applicable to certain industrial customers. The $16 million will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.
Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years.
Discontinued the IPUC-required three-tiered rate structure for residential customers.
Authorized a separate surcharge to collect approximately $3 million annually to fund future conservation programs.
The IPUC had previously issued Order No. 28992 on April 15, 2002 disallowing the lost revenue portion of the Irrigation Load Reduction Program. IPC believes that the IPUC's order is inconsistent with Order No. 28699, dated May 25, 2001, that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12 million was expensed in September 2002. IPC still believes it should be entitled to receive recovery of this amount and has asked the Idaho Supreme Court to review the IPUC's decision. If successful, IPC would record any amount recovered as revenue.
In the May 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. The IPUC subsequently issued Order No. 28772 authorizing recovery of $168 million, but deferring recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million, the IPUC in Order No. 28552 authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001.
In October 2001, IPC filed an application with the IPUC for an order approving inclusion in the 2002-2003 PCA of costs incurred for the Irrigation Load Reduction Program and the FMC/Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and the OPUC. The costs incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for the FMC/Astaris Load Reduction Agreement. The IPUC subsequently issued Order No. 28992 authorizing IPC to include direct costs it has accrued in the programs, subject to later adjustments in the 2002-2003 PCA year. As mentioned earlier, the IPUC also denied IPC's request to recover lost revenues experienced from the Irrigation Load Reduction Program.
The May 2000 PCA rate adjustment increased Idaho general business customer rates by 9.5 percent, and resulted from forecasted below-average hydroelectric generating conditions. Overall, the PCA adjustment increased general business revenue by approximately $38 million during the 2000-2001 rate period.
Oregon: IPC also filed applications with the OPUC to recover calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totaling six percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering approximately $2 million annually. The Oregon deferred balance is $14 million as of December 31, 2002.
FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in the Voluntary Load Reduction (VLR) Agreement between IPC and FMC/Astaris. This VLR Agreement amended the Electric Service Agreement (ESA) that governed the delivery of electric service to FMC/Astaris' Pocatello plant, which ceased operations late in 2001. On June 6, 2002, IPC and FMC/Astaris signed and filed a proposed Stipulation and Settlement Agreement (Agreement) with the IPUC and on June 10, 2002, the IPUC approved the Agreement in Order No. 29050 which included the following provisions:
The VLR payments that IPC would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million. Approximately 90 percent of this reduction will flow through the PCA mechanism as a reduction in costs to Idaho retail customers.
FMC/Astaris dismissed, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.
FMC/Astaris will pay IPC approximately $31 million through March 2003 to settle the ESA.
IPC's need to purchase power from the wholesale markets decreased during 2002 due to the ceased operation of FMC/Astaris' Pocatello plant and settlement of the above mentioned ESA.
Garnet Power Purchase Agreement
IPC and Garnet Energy LLC (Garnet), a wholly-owned subsidiary of Ida-West, entered into a power purchase agreement (PPA) on December 14, 2001 for IPC to purchase energy produced by Garnet's proposed natural gas generation facility. IPC filed an application with the IPUC for an order approving the PPA and an accounting order authorizing the inclusion in the PCA of power supply expenses associated with the purchase of capacity and energy from Garnet. Prior to the actual hearing date, Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility.
On July 24, 2002, the IPUC closed the proceeding involving IPC's petition to enter into a PPA with Garnet and directed IPC to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how IPC proposed to meet future power requirements if the Garnet facility is not built. On October 30, 2002, IPC submitted its compliance report to the IPUC, which included (1) Ida-West's notification that due to dramatic changes in the electricity industry, financing the project on acceptable terms under the PPA was impracticable, (2) Ida-West's offering of three alternatives to allow the project to go forward and (3) IPC's revised plan for meeting future load requirements absent the PPA associated with the Garnet project, including wholesale power purchases, energy exchanges, obtaining certain transmission rights, or constructing or acquiring generation resources located in IPC's service territory. Following the IPUC's acceptance of the 2002 IRP (see below), IPC continues to work on identifying and securing resources necessary to meet future power requirements. The original Garnet PPA was mutually terminated on March 5, 2003; however, the site remains viable as a future generation development.
Ida-West had capitalized $11 million related to the Garnet project as of third quarter 2002. During fourth quarter 2002, Ida-West recorded an $8 million partial write-down of its investment in equipment for this project. This partial write-down reflects the drop in prices for and increased availability of generating equipment due to the collapse of the merchant power plant development business.
Integrated Resource Plan
Every two years, IPC is required to file with the IPUC and OPUC an IRP, a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand. The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within IPC's utility service territory by mid-2005. The new resources expected to be in place at that time were the previously identified 250 MW power purchase from the Garnet project, an additional 100 MW generation resource to be determined and a 100 MW transmission upgrade to increase import capability. These resources would be used to satisfy energy demand during IPC's peak periods. Prior to 2005, IPC will continue to use purchases from the energy markets as necessary to meet short-term energy needs.
The IPUC Staff and several other interested parties filed comments responding to IPC's proposed 2002 IRP. The comments urge the IPUC not to acknowledge the IRP until (1) the Garnet issue is resolved, and (2) IPC provides additional detail on potential conservation measures that could be implemented. IPC filed reply comments on October 30, 2002 addressing those issues. The above mentioned Garnet compliance report, submitted to the IPUC on October 30, 2002, was included in those reply comments by reference. On February 11, 2003, the IPUC issued Order No. 29189, which accepted and acknowledged IPC's 2002 IRP as modified and directed IPC to implement certain changes in its 2004 IRP related to both the public process and the evaluation of demand-side options. The accepted IRP indicated the purchase of 100 MW from the wholesale market for IPC's retail customers during June, July, November and December. On February 24, 2003, IPC issued a formal RFP seeking bids for the construction of up to 200 MW of additional generation to support the growing seasonal demand for electricity in IPC's service area. Notice of an intent to bid must be submitted to IPC by March 14, 2003.
Automatic Meter Reading
On February 21, 2003, the IPUC issued Order No. 29196 which directed IPC to submit a plan no later than March 20, 2003 to replace its existing meters with advanced meters that are capable of both automated meter reading (AMR) and time-of-use pricing. In its order, the IPUC indicated that implementation of AMR meters should begin in 2003 and be completed in 2004. IPC has estimated it would cost approximately $76 million to install advanced meters with AMR capability. IPC intends to file a Petition for Reconsideration of the IPUC's order and to request a stay of the requirement to file the March 20, 2003 plan.
Nevada Jurisdiction
In 2001, the IPUC and the Public Utilities Commission of Nevada approved IPC's sale of its Nevada service territory to Raft River Electric Co-Op (Raft River). This sale transferred the distribution facilities and rights-of-way that serve about 1,250 customers in northern Nevada and about 90 customers in southern Idaho. The FERC approved a power supply agreement between IPC and Raft River.
Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size and complexity of the project. Currently, the licenses for five hydro projects have expired. These projects continue to operate under annual licenses until the FERC issues a new permanent license. Three more hydro project licenses will expire by 2010.
IPC is actively pursuing the relicensing of these projects, a process that may continue for the next 10 to 15 years. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric projects. The licenses for the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon) and the Swan Falls Project expire in 2005 and 2010, respectively. IPC is currently engaged in procedures necessary to file timely license applications for these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, IPC anticipates that it will relicense each of the eight projects.
Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls Projects. New FERC licenses are anticipated in 2003. While the actual costs of protection, mitigation and enhancement (PM&E) measures and other costs associated with the relicensing of the projects will not be known until the new license is issued by the FERC, costs associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million during the first five years of the licenses and $28 million over the following 25 years.
A final EIS has been issued for the CJ Strike project and a new FERC license is expected in 2003. While the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC, costs associated with the license (assuming a 30-year license) are expected to total approximately $9 million during the first five years of the license and $38 million over the following 25 years.
The four Mid-Snake River projects, Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, and the CJ Strike projects, may affect five species of snails listed under the Endangered Species Act. See previous discussion in "LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."
The Upper and Lower Malad project license expires in July 2004 and the new license application was filed in July 2002. The application is proceeding through the normal FERC licensing process. The application includes proposed PM&E measures estimated to total (assuming a 30-year license) approximately $1 million during the first five years of the license and $3 million over the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.
The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of IPC's hydro generation capacity and 40 percent of its total generating capacity. IPC developed its draft license application with the assistance of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. The draft license application was issued in September 2002 and the final application will be filed in July 2003. The draft application includes proposed PM&E measures estimated to total approximately (assuming a 30-year license) $78 million during the first five years of the license and $100 million during the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.
At December 31, 2002, $50 million of pre-relicensing costs were included in Construction Work in Progress (CWIP) and $6 million of pre-relicensing costs were included in Electric Plant in Service. The pre-relicensing costs are recorded and held in CWIP until a new permanent license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Pre-relicensing costs as well as costs related to the new licenses, as referenced above, will be submitted to regulators for recovery through the rate-making process.
Regional Transmission Organizations
In December 1999, the FERC, in its landmark Order No. 2000, said that all companies with transmission assets must file to form Regional Transmission Organizations (RTOs) or explain why they cannot. Order No. 2000 is a follow up to Order Nos. 888 and 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties. By encouraging the formation of RTOs, the FERC seeks to further facilitate the formation of efficient, competitive wholesale electricity markets.
In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an entity that will operate the transmission grid in seven western states. RTO West will have its own independent governing board. The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid.
These FERC filings represent a portion of the filing necessary to form RTO West. However, substantial additional filings will be necessary to include the tariff and integration agreements associated with the new entity. State approvals also need to be obtained. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving with modification the majority of the proposed plan for development of a RTO by ten utilities in the northwest and Canada and the BPA. IPC is one of the filing utilities. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but can also provide a basic framework for standard market design for the west". Further development of the RTO West proposal by the filing utilities continues.
In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design for regulated utilities. If implemented as proposed, the NOPR will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC's intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The proposed rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets to manage congestion. The market would be administered by RTOs, or Independent Transmission Providers. RTOs would also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand-side programs to reduce transmission constraints and meet regional energy requirements. Finally, the proposed rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the proposed rules were due during the last months of 2002 and additional comments are due the first part of 2003. The FERC currently anticipates that the final rules will be in place in mid-2003 and the contemplated market changes will take place in 2003 and 2004.
OTHER MATTERS:
New Accounting Pronouncements
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. SFAS 143 requires an entity to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If at the end of the asset's life the recorded liability differs from the actual obligations paid, a gain or loss would be recognized at that time. As a rate-regulated entity, IPC expects to record regulatory assets and liabilities instead of accretion, depreciation and gains or losses, if the criteria for such treatment are met. SFAS 143 is effective beginning in 2003.
A detailed assessment of the applicability and implications of SFAS 143 has been performed. AROs related to IPC's three jointly owned coal-fired generation facilities, its transmission and distribution facilities and the Bridger Coal mine, which is owned by an equity-method investee have been identified. When adopted in 2003, IPC expects to record ARO liabilities of $12 million and fixed assets of $6 million, with the offset to regulatory assets. These amounts do not include an amount for the transmission and distribution facilities, because, based on the indeterminate life of these assets, an ARO calculation cannot be made.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred, rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity. This standard supersedes EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 is not expected to have a material effect on IDACORP or IPC's financial statements.
EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," reached a consensus to rescind EITF 98-10, the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS 133. The consensus regarding the rescission of EITF 98-10 is applicable for fiscal periods beginning after December 15, 2002. Energy trading contracts not within the scope of SFAS 133 that are purchased after October 25, 2002, but prior to the implementation of the consensus, are not permitted to apply mark-to-market accounting. In addition, effective on January 1, 2003, all energy trading contracts previously accounted for at fair value under EITF 98-10 must be adjusted to historical cost unless those contracts meet the definition of a derivative under SFAS 133. This adjustment will be recorded as a cumulative effect of adoption of a new accounting principle. The rescission of EITF 98-10 will not have a material effect on IDACORP or IPC's financial statements, as substantially all of their energy trading contracts meet the definition of a derivative under SFAS 133.
EITF 02-3 also reached a consensus that gains and losses on derivative instruments within the scope of SFAS 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. In anticipation of this requirement, IDACORP has elected to change its presentation of energy trading activities from gross to net presentation, in accordance with the option allowed under EITF 98-10. Prior periods have been reclassified to conform to current presentation. Therefore operating revenues for the energy marketing segment include revenues from the sale of electricity and gas netted against the cost of purchased power and natural gas. Additionally, all financial transactions and unrealized income are presented on a net basis as operating revenue. Operating expenses include general and administrative expenses, bad debt reserves, transmission expenses and broker fees. The net financial position and results of operations of IDACORP were not affected by this change in presentation.
In November 2002 the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The disclosure requirements in this Interpretation are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of this Interpretation is not expected to have a material effect on IDACORP and IPC's financial statements.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." This Interpretation clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or in which equity investors do not bear the residual economic risks. The Interpretation applies to variable interest entities in which an enterprise obtains an interest after that date. It applies in the fiscal year or interim period beginning after June 15, 2003 to variable interest entities in which an enterprise holds a variable interest that was acquired before February 1, 2003. IDACORP and IPC have determined that it is not reasonably possible that they will be required to consolidate or disclose information about a variable interest entity upon the effective date of this Interpretation.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP and IPC are exposed to various market risks, including changes in interest rates, changes in certain commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at December 31, 2002.
Interest Rate Risk
IDACORP and IPC are exposed to changes in interest rates through the issuance of fixed-rate and variable-rate debt. The following table summarizes the carrying amount and interest rates by expected maturity date of debt obligations at December 31, 2002 (in thousands of dollars):
The majority of debt is held in fixed rate securities with embedded call options. By nature, the market value of variable rate debt is not sensitive to changes in interest rates, and short-term borrowings do not give rise to significant interest rate risk because they generally have maturities of less than three months.
Commodity Price Risk
Utility: IPC is exposed to changes in commodity prices related to the purchases and sales of electricity as part of its ongoing utility operations. IPC is exposed to this risk to the extent that a portion of the electric energy it is required to sell to its customers at fixed rates may be purchased at wholesale electric market prices, which can be higher than the fixed sales rate received. IPC's exposure to this risk is offset to some extent by the previously discussed PCA mechanism in place in Idaho. The objective of IPC's market price risk management program is to mitigate the risk associated with the purchase and sale of electricity, while balancing this risk against system reliability and cost considerations.
IPC has adopted a risk management policy to address commodity price risk. The Risk Management Committee (RMC), comprised of IPC officers and other senior staff, oversees the risk management program. On a regular basis, the RMC reviews multiple system resource and load projections and evaluates the potential impacts of changes in four key variables, wholesale prices, system loads, system resources and streamflow conditions. The RMC controls the risk by assessing the impact of changes in the variables on power supply cost and projected volumetric surplus and deficit data, and by reviewing forward price curves for electricity and gas. The RMC then orders an appropriate risk mitigating action. Actions may be undertaken only with creditworthy counterparties.
On August 1, 2002, due to the wind down of energy marketing, all utility-related wholesale energy and gas transaction processes were returned to IPC. These activities are focused on meeting system requirements and capitalizing on system-related opportunities that can be risk managed.
Energy Trading: IE buys and sells financial and physical natural gas and electricity commodity contracts as part of its business, exposing IE to electricity and natural gas commodity price risk as well as interest rate risk. IE has a risk management policy defining the limits within which it contains its commodity price risk. IE trades commodity futures, forwards, options and swaps as a method of managing the commodity price risk and optimizing the profitability of its electricity and natural gas trading. IE also transacts in interest rate futures and swaps to manage the interest rate risk embedded in its commodity portfolio.
When buying and selling energy, the volatility of energy prices can have a significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry, IE's RMC, comprised of IDACORP and IE officers, oversees IE's risk management program as defined in the risk management policy. The objective of IE's risk management program is to manage the risk associated with the purchase and sale of natural gas and electricity - within levels established by the RMC. IE's policy also allows the use of these commodity derivative instruments for trading purposes in support of its operations.
The value-at-risk (VAR) measure is a tool used by IE's RMC to understand on a daily basis the potential impact on earnings arising from changes in market prices.
The December 31, 2002, VAR for energy marketing operations is approximately $1 million at both a 95 and 99 percent confidence level and for a holding period of one business day. The average VAR for 2002 at a 95 percent confidence level and one-day holding period was $1 million. The VAR was calculated using an analytic VAR methodology. This methodology computes VAR based upon positions and forward market prices as of December 31, 2002, and historical forward price volatility and correlation. The VAR is understood to be a forecast and is not guaranteed to occur. The 95 percent confidence level and one-day holding period imply that there is a five percent chance that the daily loss will exceed approximately $1 million. The 99 percent confidence level implies a one percent chance that daily loss will exceed $1 million. The VAR calculation is principally affected by market prices and volatility of prices. The RMC actively manages the risk to keep IE's trading activities within trading limits.
Credit Risk
Utility: IPC is subject to credit risk based on its activity with market counterparties. IPC is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. IPC mitigates this exposure by actively establishing credit limits, measuring, monitoring, reporting, using appropriate contractual arrangements and transferring of credit risk through the use of financial guarantees, cash or letters of credit. A current list of acceptable counterparties and credit limits is maintained.
Energy Trading: IE is exposed to counterparty credit risk as part of its energy trading business. This risk is defined as exposure to decreases in expected earnings or cash flow when a counterparty to an energy commodity contract cannot or will not pay or deliver. To manage counterparty credit risk within acceptable levels, the RMC has established credit risk limits for each counterparty. Credit risk exposure is measured and reported daily to members of the RMC. In order to provide further protection from a counterparty's deteriorating creditworthiness, IE utilizes industry standard agreements containing various protective creditworthiness provisions. Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts. This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile.
At year-end 2002, 63 percent of the credit exposure related to IE's unrealized positions was with investment grade counterparties. Two percent was with non-investment grade counterparties and the remaining 35 percent was with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. Nearly 50 percent of IE's total credit exposure is to one investment grade counterparty under a contract with less than two years remaining. The following table presents the maturity of credit risk exposure for energy marketing at December 31 2002:
Equity Price Risk
IDACORP and IPC are exposed to price fluctuations in equity markets, primarily through their pension plan assets, a mine reclamation trust fund owned by an equity-method investment of IPC, and other equity investments at IPC. A hypothetical ten percent decrease in equity prices would result in an approximate $2 million decrease in the fair value of financial instruments that are classified as available-for-sale securities.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
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IDACORP, Inc.
Consolidated Statements of Income
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Balance Sheets
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Shareholders' Equity
The accompanying notes are an integral part of these statements.
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these statements
IDACORP, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.
IDACORP announced in 2002 that IE, a marketer of electricity and natural gas, would wind down its operations.
IDACORP's other subsidiaries include:
Ida-West Energy (Ida-West) - developer and manager of independent power projects;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services, Inc. (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider; and
IDACOMM - provider of telecommunications services.
Principles of Consolidation
The consolidated financial statements include the accounts of IDACORP and wholly-owned or controlled subsidiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities in which IDACORP and its subsidiaries do not have control, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual results could differ from those estimates.
System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon and Wyoming.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are expensed to operations. Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 3.00 percent in 2002, 2.98 percent in 2001 and 2.94 percent in 2000.
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction (AFDC) represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the rate making process over the service life of the related property through increased revenues resulting from higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2002, 2001 and 2000 were 4.3 percent, 5.4 percent, and 8.3 percent, respectively. IPC's reductions to interest expense for AFDC were $2 million, $4 million and $2 million, and other income included $0.3 million, $1 million and $3 million for 2002, 2001 and 2000, respectively.
Revenues
In order to match revenues with associated expenses, IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at month-end.
IE reports marketing and trading revenues and expenses on a net basis, using the mark-to-market method of accounting. Revenues and expenses for prior years have been reclassified to conform to the current presentation. Energy marketing revenues include sales of electricity and gas netted against purchases, whether physically settled or net settled. Additionally, all financial transactions and unrealized income are presented on a net basis in operating revenues. Other cost of revenues items such as transmission and broker fees are reported as operating expenses.
Power Cost Adjustment
IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail electric customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment.
Income Taxes
The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and liabilities and deferred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction, IPC's deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation computed using book lives on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates (see Note 2).
The State of Idaho allows a three-percent investment tax credit (ITC) upon certain qualifying plant additions. ITC's earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned.
Earnings Per Share
The computation of diluted earnings per share (EPS) differs from basic EPS only due to including potentially dilutive shares related to stock-based compensation awards. The diluted EPS calculation includes immaterial amounts of potentially dilutive shares for the periods presented.
The diluted EPS computation for 2002 and 2001 excluded 849,000 and 274,000 common stock options, respectively, because the options' exercise prices were greater than the average market price of the common stock during the years. These options expire from 2010 to 2012, and were still outstanding at the end of 2002. There were no such options excluded from the diluted EPS calculation in 2000.
Stock-Based Compensation
At December 31, 2002, two stock-based employee compensation plans existed, which are described more fully in Note 9. These plans are accounted for under the recognition and measurement principles of Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of restricted stock are reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and EPS if the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation," had been applied to stock-based employee compensation:
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporary investments with maturity dates at date of acquisition of three months or less.
Investments
Investments in marketable securities are accounted for in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." These investments are classified as available-for-sale securities, and are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income. Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered other than temporary. Other than temporary declines in market value are included in other income in the Consolidated Statements of Income.
IFS invests in affordable housing projects that are accounted for in accordance with Emerging Issues Task Force (EITF) Issue No. 94-1, "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects," and shown in the caption "Investments" on the balance sheet. IFS accounts for these investments using the equity method. All projects are reviewed periodically for impairment. At December 31, 2002 and 2001 the net affordable housing projects included in investments were $126 million and $95 million.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the electricity and natural gas markets. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas as well as to optimize its energy marketing portfolio. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established by SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading Activities."
Regulation of Utility Operations
IPC follows SFAS 71, "Accounting for the Effects of Certain Types of Regulation," and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating IPC. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets in the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains (losses) on marketable securities, IPC's proportionate share of unrealized holding gains (losses) on marketable securities held by an equity investee, and the changes in additional minimum liability under a deferred compensation plan for certain senior management employees and directors.
Adopted Accounting Standards
On January 1, 2002, SFAS 142, "Goodwill and Other Intangible Assets," was adopted. SFAS 142 requires that goodwill and certain intangible assets no longer be amortized, but instead be tested for impairment at least annually.
As required by the statement, transitional and annual impairment tests have been completed on the goodwill balance of $13 million, related to the acquisitions of IdaTech and Velocitus. There was no impairment of goodwill based on these tests. Goodwill impairment tests will be performed at least annually, and more frequently if circumstances indicate a possible impairment.
The following table presents IDACORP's net income and earnings per share, adjusted to exclude goodwill amortization expense, for the three years ended December 31:
SFAS 142 also includes provisions related to reclassification of intangible assets and reassessment of useful lives of intangible assets. There were no intangible assets affected by these provisions.
In January 2002, SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," was adopted. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets, superseding SFAS 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of." The adoption of SFAS 144 did not have a significant effect on IDACORP or IPC's financial statements.
In June 2001, the Derivative Implementation Group of the Financial Accounting Standards Board (FASB) issued Implementation Issue C-15, "Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity," concluding that contracts subject to book-outs were not eligible for the normal purchase and sales exception in SFAS 133. Therefore, certain contracts were recorded as derivatives in prior periods. However, this Implementation Issue was revised in October 2001 and December 2001, and now allows these contracts to qualify for the exception. This revision applies only to electric utilities, due to the unique nature of the industry. IPC completed an evaluation of the effect of this revised Implementation Issue on its treatment of booked-out contracts and determined that contracts previously classified as derivatives were exempt. This change did not have a material effect on IDACORP or IPC's financial statements.
New Accounting Pronouncements
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. SFAS 143 requires an entity to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If at the end of the asset's life the recorded liability differs from the actual obligations paid, a gain or loss would be recognized at that time. As a rate-regulated entity, IPC expects to record regulatory assets and liabilities instead of accretion, depreciation and gains or losses, if the criteria for such treatment are met. SFAS 143 is effective beginning in 2003.
A detailed assessment of the applicability and implications of SFAS 143 has been performed. AROs related to IPC's three jointly owned coal-fired generation facilities, its transmission and distribution facilities and the Bridger Coal mine, which is owned by an equity-method investee, have been identified. When adopted in 2003, IPC expects to record ARO liabilities of $12 million and fixed assets of $6 million, with the offset to regulatory assets. These amounts do not include an amount for the transmission and distribution facilities, because, based on the indeterminate life of these assets, an ARO calculation cannot be made.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred, rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity. This standard supersedes EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 is not expected to have a material effect on IDACORP or IPC's financial statements.
EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," reached a consensus to rescind EITF 98-10, the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS 133. The consensus regarding the rescission of EITF 98-10 is applicable for fiscal periods beginning after December 15, 2002. Energy trading contracts not within the scope of SFAS 133 that are purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting. In addition, effective on January 1, 2003, all energy trading contracts previously accounted for at fair value under EITF 98-10 must be adjusted to historical cost unless those contracts meet the definition of a derivative under SFAS 133. This adjustment will be recorded as a cumulative effect of adoption of a new accounting principle. The rescission of EITF 98-10 will not have a material effect on IDACORP or IPC's financial statements, as substantially all of their energy trading contracts meet the definition of a derivative under SFAS 133.
EITF 02-3 also reached a consensus that gains and losses on derivative instruments within the scope of SFAS 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. In anticipation of this requirement, IDACORP has elected to change its presentation of energy trading activities from gross to net presentation, in accordance with the option allowed under EITF 98-10. Prior periods have been reclassified to conform to current presentation. Therefore operating revenues for the energy marketing segment include revenues from the sale of electricity and gas netted against the cost of purchased power and natural gas. Additionally, all financial transactions and unrealized income are presented on a net basis as operating revenue. Operating expenses include general and administrative expenses, bad debt reserves, transmission expenses and broker fees. The net financial position and results of operations of IDACORP were not affected by this change in presentation.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The disclosure requirements in this Interpretation are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of this Interpretation is not expected to have a material effect on IDACORP or IPC's financial statements.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." This Interpretation clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or in which equity investors do not bear the residual economic risks. The Interpretation applies to variable interest entities in which an enterprise obtains an interest after that date. It applies in the fiscal year or interim period beginning after June 15, 2003 to variable interest entities in which an enterprise holds a variable interest that was acquired before February 1, 2003. IDACORP and IPC have determined that it is not reasonably possible that they will be required to consolidate or disclose information about a variable interest entity upon the effective date of this Interpretation.
Concentration of Credit Risk
Although IE transacts with a number of energy trading counterparties, it has one significant investment-grade counterparty that exposes it to credit risk. At December 31, 2002, nearly 50 percent of IE's total credit exposure of $187 million was with this investment-grade counterparty, under a contract with less than two years remaining. In order to provide protection from credit risk, IE uses tools such as standard agreements containing various protective creditworthiness provisions, collateral requirements in the form of cash or letters of credit and margining agreements when credit risk exceeds certain predetermined thresholds.
Other Accounting Policies
Debt discount, expense and premium are being amortized over the terms of the respective debt issues.
Reclassifications
Certain items previously reported for years prior to 2002 have been reclassified to conform to the current year's presentation. Net income and shareholders' equity were not affected by these reclassifications.
2. INCOME TAXES:
IDACORP's effective tax rate for the year ended December 31, 2002 decreased from 34.2 percent in 2001 to a benefit of 486 percent in 2002. Tax benefit items occurring in 2002 include a tax accounting method change and the settlement of a partnership audit.
A reconciliation between the statutory federal income tax rate and the effective rate is as follows:
The provision for income taxes consists of the following:
The tax effects of significant items comprising IDACORP's net deferred tax liabilities are as follows:
Tax Accounting Method Change
During the third quarter of 2002, IDACORP filed its 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs. The former method allocated such costs primarily to construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.
The effect of the tax accounting method change has been recorded as a decrease to income tax expense for the year ended December 31, 2002 of $35 million, of which $31 million is attributable to 2001 and prior tax years, and $4 million is attributable to the 2002 tax year. The decrease to tax expense is a result of deductions on the applicable tax returns of costs that were capitalized into fixed assets for financial reporting purposes. Deferred income tax expense has not been provided because the prescribed regulatory accounting method does not allow for inclusion of such deferred tax expense in current rates. Regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.
Status of Audit Proceedings
IPC settled income tax deficiencies related to its partnership investment in the Bridger Coal Company, covering the years 1991 through 1998. The settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.
Federal income tax returns for years through 1997 have been examined by the Internal Revenue Service and substantially all issues have been settled. Management believes that adequate provision for income taxes has been made for the open years 1998 and after and for any unsettled issues prior to 1998.
3. COMMON STOCK:
At December 31, 2002 and 2001, common stock was reserved for the following reasons:
In 2001, IDACORP acquired 198,200 shares of outstanding common stock, at a cost of $8 million, for potential distribution to shareholders of an acquired entity as partial payment for the acquisition. In 2000, IDACORP acquired 156,300 shares at a cost of $7 million for the same purpose. IDACORP has issued 233,329 shares to the shareholders of the acquired entity. Of the remaining acquired shares, 61,871 have been issued, primarily in connection with our dividend reinvestment program.
IDACORP issues shares of common stock for its Dividend Reinvestment Plan (DRIP) and Employee Savings Plan (ESP) (see Note 10). In 2002, IDACORP issued 321,236 shares for the DRIP and 202,281 shares for the ESP. In 2001, IDACORP issued 16,568 shares for the ESP.
Shareholder Rights Plan
IDACORP has a Shareholder Rights Plan (Plan) designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of IDACORP. Under the Plan, IDACORP declared a distribution of one Preferred Share Purchase Right (Right) for each of its outstanding Common Shares held on October 1, 1998 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of IDACORP's Voting Stock or commences a tender offer that would result in ownership of 20 percent or more of such stock. IDACORP may redeem all but not less than all of the Rights at a price of $0.01 per Right or exchange the Rights for cash, securities (including Common Shares of IDACORP) or other assets at any time prior to the close of business on the 10th day after acquisition by an Acquiring Person of a 20 percent or greater position.
Additionally, the IDACORP Board of Directors created the A Series Preferred Stock, without par value, and reserved 1,200,000 shares for issuance upon exercise of the Rights.
Following the acquisition of a 20 percent or greater position, each Right will entitle its holder to purchase for $95 that number of shares of Common Stock or Preferred Stock having a market value of $190.
If after the Rights become exercisable, IDACORP is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold, or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase for $95, shares of the acquiring company's common stock having a market value of $190.
Any Rights that are or were held by an Acquiring Person become void if any of these events occurs. The Rights expire on September 30, 2008.
The Rights themselves do not give any voting or other rights as shareholders to their holders. The terms of the Rights may be amended without the approval of any holders of the Rights until an Acquiring Person obtains a 20 percent or greater position, and then may be amended as long as the amendment is not adverse to the interests of the holders of the Rights.
4. PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at December 31, 2002 and 2001 were as follows:
IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.
During 2002 and 2001 IPC reacquired and retired 9,945 and 6,784 shares of 4% preferred stock. As of December 31, 2002, the overall effective cost of all outstanding preferred stock was 7.03 percent.
5. LONG-TERM DEBT:
The following table summarizes long-term debt at December 31:
At December 31, 2002, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):
IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2002, none had been issued.
On March 23, 2000, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. On December 1, 2000, IPC issued $80 million of Secured Medium-Term Notes, Series C, 7.38% Series due 2007. Proceeds were used in January 2001 for the early redemption of $75 million First Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued $120 million of Secured Medium-Term Notes, Series C, 6.60% Series due 2011 with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. No amounts remain to be issued on this shelf registration statement.
On August 16, 2001, IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. On November 15, 2002, IPC issued $200 million of secured medium-term notes. This issuance of medium-term notes was divided into two series. The first was $100 million First Mortgage Bonds 4.75% Series due 2012 and the second was $100 million First Mortgage Bonds 6.00% Series due 2032. Proceeds were used to pay down IPC short-term borrowings.
In August 2001, $25 million First Mortgage Bonds 9.52% Series due 2031 were redeemed early. Also, in March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.
The amount of first mortgage bonds issuable by IPC is limited to a maximum of $900 million and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. Substantially all of the electric utility plant is subject to the lien of the indenture.
Pollution Control Revenue Bonds, Series 1984, due December 1, 2014, are secured by First Mortgage Bonds, Pollution Control Series A, which were issued by IPC and are held by a Trustee for the benefit of the bondholders.
On April 26, 2000, at the request of IPC, the American Falls Reservoir District issued its American Falls Refunding Replacement Dam Bonds, Series 2000, in the aggregate principal amount of $20 million for the purpose of refunding on April 26, 2000 a like amount of its bonds dated May 1, 1990. IPC has guaranteed repayment of these bonds.
On May 17, 2000, tax exempt Pollution Control Revenue Refunding Bonds Series 2000, in the aggregate principal amount of $4 million, were issued by Port of Morrow, Oregon for the purpose of refunding on August 1, 2000, a like amount of its Pollution Control Revenue Bonds, Series 1978.
At December 31, 2002 and 2001, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 6.51 percent and 6.97 percent, respectively.
At December 31, 2002, IFS had $37 million of debt with interest rates ranging from 6.03 percent to 8.59 percent due 2003 to 2011. This debt is collateralized by investments in affordable housing projects with a net book value of $126 million at December 31, 2002.
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IDACORP's financial instruments has been determined using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable, fixed rate long-term debt and investments and other property are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.
7. NOTES PAYABLE:
At December 31, 2002, IDACORP had a $350 million credit facility that expires March 25, 2003, and a $140 million credit facility that expires March 26, 2005. Under these facilities IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities.
At December 31, 2002, IPC had regulatory authority to incur up to $350 million of short-term indebtedness. IPC has a $200 million credit facility that expires March 25, 2003. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities.
Balances and interest rates of short-term borrowings were as follows at December 31 (in thousands of dollars):
8. COMMITMENTS AND CONTINGENT LIABILITIES:
IPC is currently purchasing energy from 67 on-line cogeneration and small power production facilities with contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from these facilities. During the year ended December 31, 2002, IPC purchased 692,414 MWh at a cost of $44 million.
IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Company, a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31, 2002.
From time to time IDACORP and IPC are a party to various other legal claims, actions and complaints not discussed below. IDACROP and IPC believe that they have meritorious defenses to all lawsuits and legal proceedings in which they are defendants and will vigorously defend against them although they are unable to predict with certainty whether or not they will ultimately be successful. However, based on the companies evaluation, they believe that the resolution of these matters will not have a material adverse effect on IDACORP or IPC's consolidated financial positions, results of operations or cash flows.
Legal Proceedings
Overton Power District No. 5: IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5 (Overton), a Nevada electric improvement district, based on Overton's breach of its power contracts with IE. The July contract provided for Overton to purchase 40 MW of electrical energy per hour from IE at $88.50 per MWh, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.
IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim claiming, among other things, that IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in the amount to be proved at trial. Overton also asserts that the contract is unenforceable or subject to rescission. IE believes Overton's assertions are without merit. IE and Overton filed cross motions for summary judgment that have been denied by the Court. The parties continue with discovery in the lawsuit. Trial is scheduled to commence on May 5, 2003.
IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain and IE has not yet completed discovery, IE continues to believe that it should prevail on the merits. At December 31, 2002, IE had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. The recoverability of the asset is subject to Overton's willingness and ability to raise its rates as provided for in the contract.
Truckee-Donner Public Utility District: In 2002, IE received notice from the Truckee-Donner Public Utility District (Truckee), located in California, asserting that IE was in purported breach of, and that Truckee has the right to renegotiate certain terms of, the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities. Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWh.
On May 30, 2002, IE filed a lawsuit against Truckee in the Idaho State District Court in and for the County of Ada. This lawsuit was later removed to the United States District Court for the District of Idaho.
On July 23, 2002, Truckee filed a complaint against IPC, IE and IDACORP with the FERC seeking relief under its long-term power contract for the purchase of wholesale electric power from IPC and IE.
On January 3, 2003, the companies and Truckee reached a settlement of all proceedings pending between the parties. Pursuant to the settlement, Truckee has agreed to pay the companies $26 million on or before April 4, 2003. Incident to the settlement, IE also entered into an Interim Power Sales Agreement with Truckee through March 31, 2003 that replaces the original long-term power contract. The settlement of this dispute is not anticipated to have a material effect on the companies' consolidated financial positions, results of operations or cash flows.
United Systems, Inc., f/k/a Commercial Building Services, Inc.: On March 18, 2002, United Systems, Inc. (United Systems) filed a complaint in Idaho State District Court in and for the County of Ada against IDACORP Services Co., a subsidiary of IDACORP, dba IDACORP Solutions. United Systems is a heating, ventilation, refrigeration and plumbing contracting company that entered into a contract with IDACORP Services in December 2000.
Under the terms of the contract, IDACORP Services authorized United Systems to do business as "IDACORP Solutions." The contract was to be effective from January 2001 through December 2005.
In November 2001, IDACORP Services notified United Systems that IDACORP Services was terminating the contract for convenience. The contract allowed for such termination but required the terminating party to compensate the other party for all costs incurred in preparation for, and in performance of the contract, and for reasonable net profit for the remaining term of the contract. United Systems claims $7 million in net profits lost and costs incurred.
IDACORP Services asserts that termination related compensation owed to United Systems, if any, is substantially less than the amount claimed by United Systems.
On August 8, 2002, United Systems filed an amended complaint adding IDACORP, IE, and IPC as additional defendants claiming they should be held jointly and severally liable for any judgment entered against IDACORP Services. The parties in this matter agreed to delay the jury trial set for June 13, 2003 and reset it to begin on November 10, 2003.
On October 4, 2002, United Systems, Inc. filed a Motion for Partial Summary Judgment as to their damages. United Systems has estimated their damages to be approximately $7 million as stated above. Oral argument on the motion was heard on November 21, 2002. No decision has been entered on the Motion for Partial Summary Judgment as of this date.
The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.
Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20-MW purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per MWh. In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleges that the assignment was void and unenforceable, and seeks restitution from IE and IDACORP, or in the alternative, Grays Harbor alleges that the contract should be rescinded or reformed. Grays Harbor seeks as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.
IDACORP, IPC and IE had this action removed from the state court to the United States District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the Federal District Court lacked jurisdiction as the matter is preempted under the FPA by the FERC. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003.
State of California Attorney General: The California Attorney General (AG) filed the complaint in this case in the California Superior Court in San Francisco on May 30, 2002. This is one of thirteen virtually identical cases brought by the AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair competition law - California Business and Professions Code Section 17200. Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice . . . ." The AG alleges that IPC engaged in unlawful conduct by violating the Federal Power Act (FPA) in two respects: (1) by failing to file its rates with the FERC as required by the FPA; and (2) charging unjust and unreasonable rates in violation of the FPA. The AG alleges that there were "thousands of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions." Pursuant to Business and Professions Code Section 17206, the AG seeks civil penalties of up to $2,500 for each alleged violation. On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002, the AG filed a motion to remand back to state court. The court previously denied the AG's prior motions to remand back to state court in the companion cases. The court heard IPC's Motion to Dismiss on September 26, 2002. The court has not yet ruled on the Motion to Dismiss. IPC intends to vigorously defend its position in this proceeding and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerge from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara Matthews in their personal capacities. Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C., and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C., Duke Energy Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. Plaintiffs asserted various claims that the defendants violated California Antitrust Law (the Cartwright Act), Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business & Professions Code Section 17200, et seq. Among the acts complained of are bid rigging, information exchanges, withholding of power, and various other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.
On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC. Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq. As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the PMC as to any power Reliant purchased through the California markets.
Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the Federal District Court granted Plaintiffs' Motion to Remand to State Court, and Defendants' Motion to Stay the Remand Order while they appeal the Order. As a result of the various motions, no trial date is set at this time. The companies cannot predict the outcome of this proceeding, nor can they evaluate the merits of any of the claims at this time but they intend to vigorously defend this lawsuit.
Idaho Rivers United: On December 10, 2002, Idaho Rivers United filed a complaint against IPC in U.S. District Court for the District of Idaho. The complaint alleges that IPC violated the Clean Water Act by discharging an amount of dredged and fill material into the navigable waters of the Snake River in excess of that allowed by a Section 404 permit issued by the U.S. Army Corps of Engineers. The action relates to work completed by IPC, pursuant to a Section 404 permit issued by the Corps on September 3, 1999, in the area of the tailrace downstream of IPC's Bliss hydroelectric project on the Snake River in Idaho. Idaho Rivers United asks the court to impose civil penalties on IPC under sections 309(d) and 505(a) of the Clean Water Act [33 U.S.C. Sections 1319(d) and 1365(a)], require IPC to pay for any remedial or restoration work necessary to amend any environmental harm caused by the alleged violation, and pay reasonable attorney fees. IPC received an extension of time in which to respond to the complaint and is having settlement discussions with Idaho Rivers United.
IPC cannot predict the outcome of this proceeding, nor can it evaluate the merits of any of the claims at this time but it intends to vigorously defend this lawsuit.
California Energy Situation: As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation. The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX exchange defaulted on a payment to the exchange, the other participants were required to pay their allocated share of the default amount to the exchange. The allocated shares were based upon the level of trading activity, which included both power sales and purchases, of each participant during the preceding three-month period.
On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E) and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with CalPX and the California Independent System Operator (Cal ISO) in December 2000.
IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures.
A preliminary injunction was granted by a Federal Judge in the Federal District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California.
In April 2001, PG&E filed for bankruptcy. The CalPX and Cal ISO were among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO, the receivables from these entities are at greater risk.
The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to PG&E's and SCE's liabilities. Shortly after that time, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claims it is awaiting further orders of the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. Although certain parties to the California refund proceeding urged the FERC's Presiding Administrative Law Judge to consider the chargeback amounts in his determination of who owes what to whom, in his Certification of Proposed Findings on California Refund Liability, he concluded that the matter already was pending before the FERC for disposition.
Also in April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in its June 19, 2001 order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19 order also required all buyers and sellers in the Cal ISO market during the subject time-frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology.
On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, IE believes its exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review. The latter--more than 60--have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations. The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation and although the California Parties (the California Attorney General, other state agencies and the California Investor Owned Utilities) have requested specific procedures to implement that requirement, the FERC has not yet acted on that request.
On November 20, 2002, the FERC issued an order allowing the parties to the California refund proceeding to conduct discovery for one hundred days into market manipulation by various sellers during the Western power crises of 2000 and 2001. At the conclusion of the discovery period parties alleging market manipulation are to submit their claims to the FERC and parties have until March 20, 2003 to submit evidence or comments in response, including assertions that cross-examination is warranted.
This case had been further complicated by an August 13, 2002 FERC staff (Staff) Report which included the recommendation to replace the published California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing Price (MMCP) to calculate refunds with other published indices for producing basin prices plus a transportation allowance. Staff's recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated published index prices. Staff bases its speculation in large part on a statistical correlation analysis of Henry Hub and California prices. If FERC accepts the Staff recommendation, the total amount of refunds could roughly double over earlier estimates. IE, in conjunction with others, submitted comments on the Staff recommendation - asserting that Staff's conclusions were incorrect in part on the basis of the fact that the Staff's correlation study ignored evidence of normal market forces and scarcity which created the pricing variations which Staff observed, rather than improper manipulation of reported prices. Beyond soliciting comments on the Staff recommendation, the FERC has not decided whether or how to proceed with consideration of a change in the gas pricing methodology which it previously approved.
Based upon that order and subject to possible modification based upon revision of the gas indices to be used, the Cal ISO would then be directed by the FERC to calculate revised refund amounts due from sellers of spot market power into the CalPX and Cal ISO during the refund period.
The Administrative Law Judge issued a Certification of Proposed Findings on California Refund Liability on December 12, 2002. The FERC has indicated the intention to largely conclude work on the California refund matters, including Judge Birchman's decision, the gas pricing component of its MMCP methodology and claims of market manipulation, before the end of the first quarter of 2003.
On March 3, 2003, a group of California parties, including the California Attorney General, the California Public Utilities Commission, the California Electricity Oversight Board, SCE and PG&E, filed materials with the FERC claiming that wholesale power suppliers manipulated the California market during 2000-2001. They seek approximately $8 billion in refunds for the state's ratepayers. A number of wholesale power suppliers were named in the filings, including IDACORP and IPC. IDACORP and IPC intend to vigorously defend in this matter, but they are unable to predict the outcome of this proceeding.
In addition, the July 25, 2001 FERC order established another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge (ALJ) submitted recommendations and findings to the FERC on September 24, 2001. The ALJ found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have submitted comments to the FERC respecting the ALJ's recommendations. The ALJ's recommended findings are pending at the FERC. The City of Tacoma and the Port of Seattle requested that the docket be reopened to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. IE opposed that request. By order issued December 19, 2002, the FERC reopened the docket to allow interested parties to take additional discovery and present additional evidence related to alleged market manipulation and its intent on spot market sales in the Pacific Northwest. As is the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation are to submit their claims to the FERC and parties have until March 20, 2003 to submit evidence or comments in response, including assertions that cross-examination is warranted. Grays Harbor, whose civil litigation claims were dismissed, as noted above, has injected itself into the FERC proceedings asserting in discovery requests that its six month forward contract, for which performance has been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds. Grays Harbor filed testimony on March 3, 2003 requesting refunds from IPC of $5 million. The company intends to defend vigorously.
In addition, the Port of Seattle, the City of Tacoma and Seattle City Light made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest Market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. These parties did not suggest any misconduct by IE or IPC. IE and IPC expect to defend against these generic claims, but are unable to predict the outcome of this matter.
IPC transferred its non-utility wholesale electricity marketing operations to IE in June 2001 effective June 1, 2001. Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At December 31, 2002, the CalPX and Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables.
These reserves were calculated taking into account the uncertainty of collection, given the current California energy situation. Based on the reserves recorded as of December 31, 2002, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on its consolidated financial position, results of operations or cash flows.
Nevada Power Company: In February and April of 2001 IE entered into several transactions under the Western Systems Power Pool (WSPP) Agreement whereby IE agreed to deliver to Nevada Power Company (NPC) 25 MW's during the third quarter of 2002. NPC agreed to pay IE $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries. Based upon the uncertain financial condition of NPC, IE asked for further assurances of NPC's ability to pay for the power if IE made the deliveries. NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated the transactions effective July 8, 2002.
Pursuant to the WSPP Agreement IE notified NPC of the liquidated damages amount and NPC responded with a letter which describes their view of rights under the WSPP Agreement and suggests a negotiated resolution. IE will continue to pursue its rights under the WSPP Agreement. At December 31, 2002, IE had a $4 million receivable related to the NPC claim. IE will review the recoverability of the asset on an ongoing basis.
Washington Retail Consumer Class Action Complaint: The complaint in this case was filed on December 20, 2002 in the United States District Court for the Western District of Washington at Seattle, against various entities, including IPC. The complaint was served on IPC on February 3, 2003. This action seeks class action status on behalf of all persons and businesses residing in Washington who were purchasers of electrical and/or natural gas energy from any period beginning in January 2000 to the present. The complaint alleges claims under the Washington Consumer Protection Act, RCW 19.86, as well as common law claims of fraud by concealment, negligence and for an accounting. The complaint asserts that the defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the Federal Power Act, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates being unjust, unreasonable and unlawful. The plaintiff seeks certification of a class action, equitable and injunctive relief, an accounting, treble damages, attorneys' fees and costs. On February 3, 2003, another defendant, Reliant, moved to transfer the case to the Judge who is presiding over MDL No. 1405. IPC's response to the complaint is due within 30 days from the date of service. IPC intends to vigorously defend against this lawsuit and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Oregon Retail Consumer Class Action Complaint: The complaint in this case was filed on December 16, 2002 in the Circuit Court of the State of Oregon for the County of Multnomah, against various entities, including IPC. The complaint was served on IPC on February 7, 2003. The case was removed by another defendant, Reliant, to the United States District Court, District of Oregon on February 4, 2003. The complaint seeks class action status on behalf of all persons and businesses residing in Oregon who were purchasers of electrical and/or natural gas energy from any period beginning in January 2000 to the present. The complaint alleges claims under the Oregon Unfair Trade Practices Act, ORS 646.605 et seq. in addition to claims of fraud by concealment, negligence and for an accounting. The complaint asserts that the defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the Federal Power Act, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates being charged to Oregon energy consumers that were unjust, unreasonable and unlawful. The plaintiff seeks certification of a class action, equitable and injunctive relief, an accounting, attorneys' fees and costs. The action was recently removed to federal court, and IPC intends to seek an extension of time to respond. IPC intends to vigorously defend against this lawsuit and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Enron Bankruptcy Case: IE and IPC exercised their rights to terminate all contracts with Enron Power Marketing Inc. (EPMI) and Enron North America Corp. (ENA) on or about December 3, 2001, immediately after the filing of the bankruptcy case by Enron and numerous of its subsidiaries and affiliates.
IE timely submitted claims during October, 2002 in the Enron bankruptcy proceeding for net pre-petition obligations of EPMI and ENA and Enron Corp. (as Guarantor) to IE of over $17 million, primarily for power and energy delivered prior to the Enron bankruptcy, together with contingent claims based on fraud, claims arising from governmental investigations and other claims against Enron. IE and IPC have acknowledged that there are also monetary values associated with forward contracts that were terminated, which, when analyzed separately, may result in a substantial net liability to Enron after setoff of such pre-petition obligations.
For several months, IE and IPC have been trying to reach agreement with Enron, under a non-disclosure and confidentiality agreement, on amounts for both the pre-petition and future obligations in order to calculate a net termination payment value and a mutually agreed settlement value. However, the parties have not yet been able to agree on these numbers. A proposed settlement agreement was being actively negotiated.
However, on February 27, 2003, IE received a complaint filed by EPMI in the U.S Bankruptcy Court, Southern District of New York. The complaint asserts that EPMI is entitled to a Termination Payment of $39 million, plus interest from the termination date. The complaint asks for declaratory relief, damages and makes objections to IE's Proof of Claim. The answer to the complaint is due 30 days from the date of the Summons, dated February 26, 2003. A pretrial conference has been scheduled in the New York Bankruptcy Court on April 10, 2003.
On February 28, 2003, IE received a Notice of Presentment of Enron's proposed Order Governing Mediation of Trading Cases. Enron intends to present its proposed order, which would refer 25 listed pending adversary proceedings involving trading agreements to another bankruptcy judge for mediation, to the Bankruptcy Court on March 4, 2003. Although the adversary proceeding against IE is not among the listed proceedings, the proposed order would also refer "any future adversary proceedings" to the mediation judge. Certain parties filed objections to the proposed order on March 3, 2003, which will be considered at the March 4 hearing.
Enron's counsel has agreed that since the proceeding against IE was not among the 25 listed in the proposed order, it was not necessary for IE to file objections or to meet certain other deadlines set forth in the proposed order. However, Enron will likely seek to refer the IE proceeding to the mediation judge.
While IE and IPC intend to continue to pursue settlement, if the matter is not resolved by settlement, IE and IPC intend to dispute the amounts claimed by EPMI and will vigorously defend against the complaint and aggressively prosecute any counterclaims it may have against Enron.
The companies believe that the liabilities accrued at December 31, 2002 are sufficient to cover the payments considered probable under this litigation or potential settlement.
9. STOCK-BASED COMPENSATION:
IDACORP has two stock-based compensation plans that are intended to align employee and shareholder objectives related to its long-term growth.
IDACORP adopted the 2000 Long-Term Incentive Compensation Plan (LTICP) for officers, key employees and directors. The LTICP permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards.
The maximum number of shares available under the LTICP is 2,050,000. In 2002 and 2001, IDACORP issued 355,000 and 274,000 stock options with an exercise price equal to the market price of IDACORP's stock on the date of grant. The maximum term of the options is ten years, and they vest ratably over a five-year period. In accordance with APB 25, no compensation costs have been recognized for the option awards.
Stock option transactions are summarized as follows:
The outstanding options have a range of exercise prices from $35.81 to $40.31. As of December 31, 2002, the weighted average remaining contractual life is 8.4 years.
IDACORP also has a restricted stock plan for certain key employees. Each grant made under this plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative earnings per share performance goals. At December 31, 2002, there were 201,539 remaining shares available under this plan.
Restricted stock awards are compensatory awards and IDACORP accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 2002, 2001 and 2000, total compensation accrued under the plan was less than $1 million annually.
The following table summarizes restricted stock activity for the years 2002, 2001 and 2000:
For purposes of the pro forma calculations in Note 1, the estimated fair value of the options and restricted stock are amortized to expense over the vesting period. The fair value of the restricted stock is the market price of the stock on the date of grant. The fair value of each option granted was estimated at the date of grant using the Binomial option-pricing model with the following assumptions:
10. BENEFIT PLANS:
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee's final average earnings. IPC's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2002, 2001 and 2000. The trustee invests the plan assets primarily in listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate.
IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. This plan was financed by purchasing life insurance policies and investments in marketable securities, all of which are held by a trustee. The cash value of the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status.
The following table shows the components of net periodic benefit cost for these plans:
The following table summarizes the changes in benefit obligation and plan assets of these plans:
The following table sets forth the assumptions used at the end of each year for all IPC-sponsored pension and postretirement benefit plans:
Employee Savings Plan
IPC has an Employee Savings Plan which complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million in each of 2002 and 2001 and $3 million in 2000.
Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents.
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75%. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):
Postemployment Benefits
IPC provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment but before retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under IPC's disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits. In accordance with an IPUC order, the portion of the liability attributable to regulated activities in Idaho as of December 31, 1993, was deferred as a regulatory asset, and is being amortized over ten years.
The following table summarizes postemployment benefit amounts included in IDACORP and IPC's consolidated balance sheets at December 31 (in thousands of dollars):
11. PROPERTY PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:
The following table presents the major classifications of IPC's utility plant in service, annual depreciation provisions as a percent of average depreciable balance and accumulated provision for depreciation for the years 2002 and 2001 (in thousands of dollars):
IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. IPC's proportionate share of direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent of IPC's participation, are as follows at December 31, 2002:
IPC's wholly owned subsidiary, Idaho Energy Resources Company, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal for the Jim Bridger steam generation plant. Coal purchased by IPC from the joint venture amounted to $44 million in 2002, $43 million in 2001, and $44 million in 2000.
IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act Qualified Facilities that are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7 million in 2002, $6 million in 2001 and $8 million in 2000.
Ida-West
During fourth quarter 2002, Ida-West recorded an $8 million partial write-down of its investment in equipment for the Garnet project. This partial write-down reflects the drop in prices for and increased availability of generating equipment due to the collapse of the merchant power plant development business.
12. INDUSTRY SEGMENT INFORMATION:
IDACORP has identified two reportable operating segments, utility operations and energy marketing.
The utility operations segment has two primary sources of revenue: the regulated operations of IPC and income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity.
The energy marketing segment reflects the results of IE's electricity and natural gas marketing operations. See Note 13 - Regulatory Matters, for discussion on the wind down of energy marketing.
The following table summarizes the segment information for IDACORP's utility operations, energy marketing operations and the total of all other segments, and reconciles this information to total enterprise amounts.
13. REGULATORY MATTERS:
Wind Down of Energy Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations. In connection with the wind down, certain matters were identified that require resolution with the FERC or the IPUC. Matters that need to be resolved with the FERC include:
A utility such as IPC is entitled to transmission priority for its retail customers, while transmission for trading transactions must be purchased under the utility's open access tariff on the same basis as third parties. It appears that in some transactions this distinction was not observed;
Certain transactions between a utility and an affiliate are required to have prior FERC approval. Such prior approval was not sought for some electricity transactions between IE and IPC, such as spinning reserves and load following services, which are common industry services; and
Although IPC informed the FERC before IE was split off from IPC that it intended to move the utility's power marketing business to IE, IPC's power marketing contracts were assigned without formally obtaining the requisite prior approval of the FERC.
IE and IPC voluntarily contacted the FERC in September 2002 to discuss these matters. Since September, the FERC has made several requests for certain documents and other information all of which, except for those requests which have been deferred, IE and IPC have supplied. IE and IPC made additional filings with the FERC in November 2002, which included requests for approval of certain electricity transactions, the assignment of certain contracts between IPC and IE and termination of the Electricity Supply Management Services Agreement entered into between IPC and IE in June 2001.
On February 26, 2003, the FERC approved the assignment of certain wholesale power and transmission services agreements from IPC to IE. The FERC also found that IPC violated Section 203 of the Federal Power Act (FPA) by assigning the agreements in June 2001 without seeking prior approval from the FERC. The FERC noted that noncompliance with Section 203 of the FPA may prompt the FERC in certain instances to impose remedies as a condition of its approval; however, no such remedies were imposed in the FERC order.
Should the FERC conclude that its regulations or rate schedules were not complied with, it has significant discretion as to the appropriate remedies, if any. The FERC's remedial authority includes the authority to require refunds, to order equitable relief, to suspend the authorization to sell wholesale power at market-based rates, and, in some instances, to impose monetary penalties.
In an IPUC proceeding that has been underway since May 2001, IPC and the IPUC staff have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates. Similar state regulatory issues relating to the period prior to February 2001 were determined by the IPUC in Order No. 28852 issued on September 28, 2001. The IPUC ruled on these transactions again in Order No. 29026 for the time period from March 2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No. 29102 issued August 28, 2002. This formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. In the same order, the IPUC directed IPC to present a resolution or a status report to the IPUC no later than December 20, 2002 on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues. On December 20, 2002, a status report was filed with the IPUC reporting no significant developments. IPC committed to providing another status report to the IPUC on March 20, 2003.
IDACORP does not believe that resolution of these transactions will have any adverse impact on its ongoing operations. However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on earnings and whether it will be material.
As previously disclosed, the FERC filing made on May 14, 2001, with respect to the pricing of real-time energy transactions between IPC and IE, is still under review by the FERC. For the period June 2001 through March 2002, IE paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the period that was most favorable to IPC. This amount was credited to Idaho retail customers through the PCA. An additional $1 million has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology. However, until the FERC takes final action on this filing, rates for real-time transactions between IE and IPC are subject to adjustment.
Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at December 31, 2002 and 2001 (in thousands of dollars):
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which take effect in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment.
So far in the 2002-2003 PCA rate year actual power supply costs have exceeded those anticipated in the forecast. Below normal water conditions are still impacting power supply costs even though power supply prices are significantly lower. In addition an Irrigation Load Reduction Program was completed in the 2001-2002 PCA rate year and the Astaris Voluntary Load Reduction costs have decreased, both reducing the PCA regulatory account balance from $290 million as of December 31, 2001 to $126 million as of December 31, 2002.
On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs, consisting of:
$209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002.
$28 million of excess power supply costs forecasted for the period April 2002 through March 2003.
$18 million of unamortized costs previously approved for recovery beginning October 1, 2001. The amount authorized in October 2001 totaled $49 million. This order spreads the remaining October 2001 rate increase, which would have ended in September 2002, through May 2003.
The order also:
Denied recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program, and $2 million of other costs IPC sought to recover.
Deferred recovery of $12 million of costs related to irrigation and small general service customers. In June 2002, the IPUC issued Order No. 29065 deferring an additional $4 million applicable to certain industrial customers. The $16 million will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.
Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years.
Discontinued the IPUC-required three-tiered rate structure for residential customers.
Authorized a separate surcharge to collect approximately $3 million annually to fund future conservation programs.
The IPUC had previously issued Order No. 28992 on April 15, 2002 disallowing the lost revenue portion of the Irrigation Load Reduction Program. IPC believes that the IPUC's order is inconsistent with Order No. 28699, dated May 25, 2001, that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12 million was expensed in September 2002. IPC still believes it should be entitled to receive recovery of this amount and has asked the Idaho Supreme Court to review the IPUC's decision. If successful, IPC would record any amount recovered as revenue.
In the May 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. The IPUC subsequently issued Order No. 28772 authorizing recovery of $168 million, but deferring recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million, the IPUC in Order No. 28552 authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001.
In October 2001, IPC filed an application with the IPUC for an order approving inclusion in the 2002-2003 PCA of costs incurred for the Irrigation Load Reduction Program and the FMC/Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and the OPUC. The costs incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for the FMC/Astaris Load Reduction Agreement. The IPUC subsequently issued Order No. 28992 authorizing IPC to include direct costs it has accrued in the programs, subject to later adjustments in the 2002-2003 PCA year. As mentioned earlier, the IPUC also denied IPC's request to recover lost revenues experienced from the Irrigation Load Reduction Program.
The May 2000 PCA rate adjustment increased Idaho general business customer rates by 9.5 percent, and resulted from forecasted below-average hydroelectric generating conditions. Overall, the PCA adjustment increased general business revenue by approximately $38 million during the 2000-2001 rate period.
Oregon: IPC has also filed applications with the OPUC to recover calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC has approved rate increases totaling six percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering approximately $2 million annually. The Oregon deferred balance is $14 million as of December 31, 2002.
Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities for the years 2002 and 2001:
At December 31, 2002, IPC had $3 million of regulatory assets, primarily SFAS 112, "Employers Accounting for Postemployment Benefits" benefits and reorganization costs, that were not earning a return on investment (excluding the $328 million that relates to income taxes). The amortization period is three to four years.
In the event that recovery of costs through rates becomes unlikely or uncertain, SFAS 71 would no longer apply. If IPC were to discontinue application of SFAS 71 for some or all of its operations, then these items may represent stranded investments. If IPC is not allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant.
14. DERIVATIVE FINANCIAL INSTRUMENTS:
Energy Trading Contracts
The commodity transactions entered into by IE are classified as energy trading contracts, or derivatives. Under SFAS 133 and EITF 98-10, these contracts are recorded on the balance sheet at fair market value. This accounting treatment is also referred to as mark-to-market accounting. Mark-to-market accounting treatment can create a disconnect between recorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market value of the entire term of the contract at each reporting period and reflecting the resulting gain or loss in earnings for the period. This change in value represents the difference between the contract price and the current market value of the contract. The change in market value of the contract could result in large gains or losses recorded in earnings at each subsequent reporting period unless there are off-setting changes in value of off-setting contracts. The gain or loss generated from the change in market value of the energy trading contracts is a non-cash event. If these contracts are held to maturity, the cash flow from the contracts, and their off-setting contracts, are realized over the life of the contract.
When determining the fair value of marketing and trading contracts, IE uses actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices IE uses, when available, prices provided by other external sources. When prices from external sources are not available, IE determines prices by using internal pricing models that incorporate available current and historical pricing information. Finally, the fair market value of contracts is adjusted for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level.
The following table details the gross margin for the energy marketing operations (in thousands of dollars):
Risk Management: When buying and selling energy, the volatility of energy prices can have significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry IE's Risk Management Committee (RMC), comprised of IDACORP and IE officers, oversees IE's risk management program as defined in the risk management policy. The program is intended to manage the impact to earnings caused by the volatility of energy prices by mitigating commodity price risk, credit risk, and other risks related to the energy commodity business.
To manage the risks inherent in its portfolio, IE has established risk limits. Market and credit risk is measured and reported daily to the members of the RMC. Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts. This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile.
15. RESTRUCTURING COSTS:
In 2002, IDACORP announced two separate plans to wind down IE's energy marketing operations. The initial announcement, in June 2002, specified that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce at its Boise operations by approximately 50 percent. The second announcement, in November 2002, indicated that IE would close its Denver office by year-end 2002, would shut down its natural gas trading operation in Houston by March 2003, and would result in additional workforce reductions in Boise operations through mid-2003. Since the initial announcement in June 2002, IE has reduced its workforce by over 60 percent and will continue to reduce its workforce as contractual obligations terminate.
In 2002, IE accrued $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination and other exit-related costs. These costs are classified as "energy marketing - selling, general and administrative" on the consolidated statements of income. Of these amounts, $1 million of involuntary termination benefits have been paid as of December 31, 2002. The termination benefit expense relates to the termination of 98 employees (primarily energy traders and administrative support positions), 51 of whom had been laid off by December 31, 2002. Nineteen of the 51 employees laid off by IE in 2002 were hired by other IDACORP subsidiaries, and thus received no severance benefits.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho
We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and its subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, in 2002 the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142. Also as discussed in Note 1, the Company changed its presentation of energy trading activities in accordance with Emerging Issues Task Force Issue Nos. 98-10 and 02-3.
DELOITTE & TOUCHE LLP
Boise, Idaho
February 6, 2003
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Idaho Power Company
Consolidated Statements of Income
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Assets
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Balance Sheets
Capitalization and Liabilities
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Capitalization
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Retained Earnings
The accompanying notes are an integral part of these statements.
Idaho Power Company
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The outstanding shares of IPC's common stock were exchanged on a share-for-share basis into common stock of IDACORP on October 1, 1998 and are no longer actively traded. IPC's preferred stock and debt securities were unaffected.
Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP included in this 2002 Annual Report on Form 10-K are incorporated herein by reference insofar as they relate to IPC.
Note 1 - Summary of Significant Accounting Policies
Note 2 - Income Taxes
Note 4 - Preferred Stock of Idaho Power Company
Note 5 - Long-Term Debt
Note 7 - Notes Payable
Note 8 - Commitments and Contingent Liabilities
Note 10 - Benefit Plans
Note 11 - Property, Plant and Equipment and Jointly-Owned Projects
Note 13 - Regulatory Matters
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Stock-Based Compensation
At December 31, 2002, two stock-based employee compensation plans existed, which are described more fully in Note 9. These plans are accounted for under the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of restricted stock are reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123, "Accounting for Stock-Based Compensation," had been applied to stock-based employee compensation:
2. INCOME TAXES:
IPC's effective tax rate for the year ended December 31, 2002 decreased from 40.6 percent in 2001 to a benefit of three percent in 2002. Tax benefit items occurring in 2002 include a tax accounting method change and the settlement of a partnership audit, which resulted in a decrease to tax expense.
A reconciliation between the statutory federal income tax rate and the effective rate is as follows:
The provision for income taxes consists of the following:
The tax effects of significant items comprising IPC's net deferred tax liabilities are as follows:
6. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IPC's financial instruments has been determined using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable, fixed rate long-term debt and investments and other property are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.
9. STOCK-BASED COMPENSATION:
IDACORP adopted the 2000 LTICP for officers, key employees and directors including those of IPC. The LTICP permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards.
Stock option transactions are summarized as follows:
The outstanding options have a range of exercise prices from $35.81 to $40.31. As of December 31, 2002, the weighted average remaining contractual life is 8.3 years.
IDACORP also has a restricted stock plan for certain key employees including those of IPC. Each grant made under this plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative EPS performance goals. At December 31, 2002 there were 201,539 IDACORP shares remaining available under this plan.
Restricted stock awards are compensatory awards and IPC accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 2002, 2001 and 2000, total compensation accrued under the plan was less than $1 million annually.
The following table summarizes restricted stock activity for the years 2002, 2001 and 2000:
16. DISCONTINUED OPERATIONS:
Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations ("Energy Marketing") to IE.
Energy Marketing net assets transferred consist primarily of energy trading contracts and trading accounts receivable and accounts payable. The results of operations of Energy Marketing were previously reported on IPC's Statements of Income as "Energy marketing activities - net." For 2001 and 2000, Energy Marketing is reported as a discontinued operation.
17. RELATED PARTY TRANSACTIONS:
In exchange for the transfer of Energy Marketing to IE in June 2001, IPC received a partnership interest in IE, which was then transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. This amount represents the historical book value of the transferred Energy Marketing net assets on May 31, 2001 of $21 million and retained intercompany tax liabilities of $55 million. The notes receivable are due over periods of one to ten years and bear interest at IDACORP's overall variable short-term borrowing rate, which was 1.8 percent at December 31, 2002. The balance of this note at December 31, 2002 is approximately $22 million, including accrued interest.
In September 2002, IPC borrowed $100 million from IDACORP in order to repay a like amount of floating rate notes. This amount was repaid, with interest, on November 15, 2002.
In 2002 and 2001, IPC paid IE approximately $2 million annually under the Electricity Supply Management Services Agreement. IPC and IE requested termination of this agreement in a November 2002 FERC filing.
The following table presents IPC's sales to and purchases from IE for the years ended December 31:
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho
We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and its subsidiary as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and its subsidiary at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Boise, Idaho
February 6, 2003
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of 2002 and 2001 (in thousands of dollars except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
IDACORP, Inc.:
Idaho Power Company:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Items 10 and 11, portions of Item 12
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER INFORMATION
EQUITY COMPENSATION PLAN INFORMATION:
The following table includes information as of December 31, 2002 (March 3, 2003 as to the IDACORP, Inc. (IDACORP) Non-Employee Directors Stock Compensation Plan (DCP)) with respect to equity compensation plans where equity securities of IDACORP may be issued. There are no plans where equity securities of Idaho Power Company (IPC) may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) and the DCP.
(a)
(b)
(c)
Number of securities
remaining available for
Number of securities to
Weighted-average
future issuance under
be issued upon exercise
exercise price of
equity compensation
of outstanding options,
outstanding options,
plans (excluding securities
Plan Category
warrants and rights
warrants and rights
reflected in column (a))
Equity compensation
plans approved by
shareholders (1)
849,000
$38.50
1,402,539(2)(3)
Equity compensation
plans not approved by
shareholders (4)
-
-
88,042
Total
849,000
$38.50
1,490,581
(1)
Consists of the RSP and the LTICP.
(2)
In addition to being available for future issuance upon exercise of options, 1,201,000 shares under the LTICP may instead be issued in
connection with stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares or other
equity-based awards.
(3)
201,539 shares remain available for future issuance under the RSP.
(4)
Consists of the DCP.
Equity Compensation Plan Not Approved by IDACORP Shareholders
The DCP was adopted by the IDACORP Board of Directors effective May 17, 1999, and provided for an annual stock grant in June of each year valued at $6,000. The purpose of the DCP is to increase director's stock ownership through stock based director compensation. The DCP was amended on November 18, 1999 to increase the annual grant to stock valued at $8,000 and was amended again effective April 1, 2002. The April 1, 2002 amendment increased the annual grant to stock valued at $16,000. This increase offset the termination of the director's non-qualified deferred compensation plan. Because the IDACORP and IPC Boards of Directors are comprised of the same members, IPC non-employee directors do not receive an additional grant. The plan provides for a total of 100,000 shares that may be issued from treasury stock or purchased on the open market.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures:
The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.'s disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of a date within 90 days of the filing date of this report, have concluded that IDACORP, Inc.'s disclosure controls and procedures are effective.
The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of a date within 90 days of the filing date of this report, have concluded that Idaho Power Company's disclosure controls and procedures are effective.
(b) Changes in internal controls:
There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in IDACORP, Inc.'s or Idaho Power's internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation referred to in paragraph (a) above.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Please refer to Part II, Item 8 - "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules.
(b) Reports on SEC Form 8-K. The following Reports on Form 8-K were filed for the three months ended December 31, 2002
Items Reported
Date of Report
Filed by
Item 7 - Financial Statements and Exhibits
November 12, 2002
Idaho Power Company
Item 7 - Financial Statements and Exhibits
November 12, 2002
IDACORP, Inc.
Item 5 - Other Events and Regulation FD Disclosure
December 13,
IDACORP, Inc. and
Idaho Power Company
(c) Exhibits.
*Previously Filed and Incorporated Herein by Reference
IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2002, 2001 and 2000
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2002, 2001 and 2000
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
IDACORP, Inc.
(Registrant)
March 7, 2003
By: /s/Jan B. Packwood
Jan B. Packwood
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
By:
/s/
Jon H. Miller
/s/
Chairman of the Board
March 7, 2003
Jon H. Miller
By:
/s/
Jan B. Packwood
/s/
President and Chief Executive
"
Jan B. Packwood
Officer and Director
By:
/s/
Darrel T. Anderson
/s/
Vice President, Chief Financial
"
Darrel T. Anderson
Officer and Treasurer
(Principal Financial Officer)
(Principal Accounting Officer)
By:
/s/
Rotchford L. Barker
By:
/s/
Evelyn Loveless
"
Rotchford L. Barker
Evelyn Loveless
Director
Director
By:
/s/
John B. Carley
By:
/s/
Gary G. Michael
"
John B. Carley
Gary G. Michael
Director
Director
By:
/s/
Christopher L. Culp
By:
"
Christopher L. Culp
Peter S. O'Neill
Director
Director
By:
/s/
Jack K. Lemley
By:
/s/
Robert A. Tinstman
"
Jack K. Lemley
Robert A. Tinstman
Director
Director
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 7,
By:/s/J. LaMont Keen
J. LaMont Keen
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
By:
/s/
Jon H. Miller
/s/
Chairman of the Board
March 7, 2003
Jon H. Miller
By:
/s/
Jan B. Packwood
/s/
Chief Executive Officer
"
Jan B. Packwood
and Director
By:
/s/
J. LaMont Keen
/s/
President and Chief Operating
"
J. LaMont Keen
Officer
By:
/s/
Darrel T. Anderson
/s/
Vice President, Chief Financial
"
Darrel T. Anderson
Officer and Treasurer
(Principal Financial Officer)
(Principal Accounting Officer)
By:
/s/
Rotchford L. Barker
By:
/s/
Evelyn Loveless
"
Rotchford L. Barker
Evelyn Loveless
Director
Director
By:
/s/
John B. Carley
By:
/s/
Gary G. Michael
"
John B. Carley
Gary G. Michael
Director
Director
By:
/s/
Christopher L. Culp
By:
"
Christopher L. Culp
Peter S. O'Neill
Director
Director
By:
/s/
Jack K. Lemley
By:
/s/
Robert A. Tinstman
"
Jack K. Lemley
Robert A. Tinstman
Director
Director
CERTIFICATIONS
I, Jan B. Packwood, President and Chief Executive Officer, certify that:
1. I have reviewed this annual report on Form 10-K of IDACORP, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
I, Darrel T. Anderson, Vice President, Chief Financial Officer and Treasurer, certify that:
1. I have reviewed this annual report on Form 10-K of IDACORP, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
I, Jan B. Packwood, Chief Executive Officer, certify that:
I have reviewed this annual report on Form 10-K of Idaho Power Company;
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date:
March 7, 2003
By:
/s/Jan B. Packwood
Jan B. Packwood
Chief Executive Officer
I, Darrel T. Anderson, Vice President, Chief Financial Officer and Treasurer, certify that:
I have reviewed this annual report on Form 10-K of Idaho Power Company;
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date:
March 7, 2003
By:
/s/Darrel T. Anderson
Darrel T. Anderson
Vice President, Chief Financial
Officer and Treasurer
EXHIBIT INDEX
Exhibit Number
10(h)(v)
IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.
10(h)(x)
IDACORP Energy, L.P. 2002 Incentive Plan.
10(h)(xi)
IDACORP, Inc. 2002 Executive Incentive Plan.
Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)
12(a)
Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)
12(b)
Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.)
12(c)
Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.)
12 (d)
Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IPC)
12(e)
Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC)
12(f)
Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC)
12(g)
Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC)
Subsidiaries of IDACORP, Inc. and IPC
Independent Auditors' Consent.
99(a)
Certification of Chief Executive Officer of IDACORP, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99(b)
Certification of Chief Finanical Officer of IDACORP, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99(c)
Certification of Chief Executive Officer of Idaho Power Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99(d)
Certification of Chief Finanical Officer of Idaho Power Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.