ITEM 1. BUSINESS
OVERVIEW
IDACORP, Inc. (IDACORP) is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power Company (Idaho Power). IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.
Idaho Power was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities that wound down operations in 2003.
Idaho Power is IDACORP’s only reportable business segment, contributing 98.5 percent of IDACORP’s net income in 2010. Segment data is presented in Note 17 - “Segment Information” to the consolidated financial statements included in this report. At December 31, 2010, IDACORP had 2,032 full-time employees, 2,016 of whom were employed by Idaho Power, and 19 part-time employees, all of whom were employed by Idaho Power.
IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power has a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power continuously evaluates and refines its business strategy to ensure coordination among and integration of all functional areas of the company. Idaho Power’s business strategy seeks to balance the interests of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. The strategy includes:
RESPONSIBLE PLANNING: Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet anticipated population growth and increasing electricity demand. This planning process integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the communities Idaho Power serves.
RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources Idaho Power and the communities it serves depend upon. Additionally, the strategy considers workforce planning and employee development and retention related to these strategic elements.
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RESPONSIBLE ENERGY USE: Idaho Power's business strategy includes energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standards (RPS) legislation. The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions.
IDACORP and Idaho Power make available free of charge on their websites 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 (SEC). IDACORP's website is www.idacorpinc.com and can also be accessed through a link to the IDACORP website on the Idaho Power website at www.idahopower.com. The contents of the above-referenced website addresses are not part of this Annual Report on Form 10-K. Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from the SEC’s website, www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.
IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.
UTILITY OPERATIONS
Idaho Power’s service territory covers approximately 24,000 square miles in southern Idaho and eastern Oregon, with an estimated population of one million. Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 71 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, 2010, Idaho Power supplied electric energy to approximately 492,000 general business customers. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, forest products, beet sugar refining, and winter recreation.
Weather, customer demand, and economic conditions impact electricity sales and, therefore, utility revenues are not generated, and associated expenses are not incurred, evenly during the year. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.
Electric utilities have historically been recognized as natural monopolies and have operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), and as a regulated electric utility Idaho Power is generally not subject to retail competition. Idaho Power is also under the jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities.
Rates and Revenues
Retail:
Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to sufficiently cover its operating costs and provide a reasonable rate of return. Idaho Power uses general rate cases, power cost adjustment (PCA) mechanisms, a fixed cost adjustment (FCA) mechanism, and subject-specific filings to recover its costs of providing service and to earn a return on investment.
Retail prices are determined through formal ratemaking proceedings that generally include testimony by participating parties, data requests, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, include Idaho Power, the IPUC or
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OPUC, and intervenors. The IPUC and OPUC are required to ensure that the prices and terms of service are fair, non-discriminatory, and provide the company an opportunity to earn a fair return on investment.
In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific authorization from the IPUC or OPUC. Such amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs.
For additional information, including information on significant rate cases and proceedings, see the “Regulatory Matters” section of Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
Developments with Special Customer Electric Service Agreements
Idaho Power is authorized to enter into special electric service arrangements with customers who have an aggregate power requirement that exceeds 20 MW. Notable recent developments with respect to two of those arrangements are described below.
Micron: On February 12, 2010, the IPUC approved a replacement electric service agreement between Idaho Power and Micron Technology, Inc. (Micron) that provided operating and planning benefits to Idaho Power while allowing Micron to reduce its contract demand to 60 MW. The prior agreement provided for a contract demand of 85 MW.
Hoku: In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility being constructed in Pocatello, Idaho. The initial term of the agreement was four years beginning June 1, 2009, subsequently changed to December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. Hoku was still not taking significant service as of December 1, 2009, and Idaho Power agreed to temporarily waive the minimum billed energy charge in the Hoku special contract, effective December 1, 2009. The temporary waiver, which was approved by the IPUC, remains in effect until the month the contract load factor first exceeds 70 percent of the total contract demand, or March 31, 2011, whichever comes first. While the substantial delay in the starting date for Hoku’s energy purchases under the electric service agreement reduces Idaho Power’s expected revenues, the revenue reductions are largely offset by corresponding reductions in Idaho Power’s costs of providing service to Hoku.
Wholesale:
As a public utility under Part II of the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its Open Access Transmission Tariff (OATT). Idaho Power’s OATT is revised each year based on financial and operational data Idaho Power files annually with the FERC in its Form 1. The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation. Such standards, which are applicable to Idaho Power, were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of these standards.
Idaho Power has one firm wholesale power sales contract, with Raft River Electric Cooperative, for up to 15 MW. This contract expires in September 2011. Idaho Power has one wholesale reserve sales contract, with United Materials of Great Falls, Inc. The agreement requires Idaho Power to carry energy reserves in association with an energy sales agreement between Idaho Power and United Materials from the Horseshoe Bend Wind Farm located in Montana. The term of the agreement runs seasonally through May 2013.
Idaho Power participates in the wholesale energy market by buying power to help meet load demands and selling power that is in excess of load demands. Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans and are influenced by customer load, market prices, generating costs, and availability of generating resources. Some of Idaho Power's hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run hydroelectric generation units and when to store water in reservoirs. These decisions affect the timing and volumes of market purchases and market sales. Even in below-normal water years, there are opportunities
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to vary water usage to maximize generation unit efficiency, capture marketplace economic benefits, and meet load demand. Wholesale energy market prices and compliance factors, such as allowable river stage elevation changes and flood control requirements, influence these dispatch decisions.
Energy Sales:
The table below presents Idaho Power’s revenues and energy use by customer type for the last three years. Approximately 95 percent of Idaho Power’s general business revenue comes from customers located in Idaho, with the remainder coming from customers located in Oregon. Idaho Power’s operations are discussed further in Part II, Item 7 - “MD&A - Results of Operations - Utility Operations.”
Power Supply
Idaho Power primarily relies on company-owned hydroelectric, coal, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River and market purchases and sales are used to balance supply and demand throughout the year. Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
Weather, customer growth, and economic conditions impact power supply costs. Drought conditions and customer growth cause a greater reliance on more expensive purchased power to meet load requirements. Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric generating facilities and reduce the need for purchased power. Economic conditions can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power.
Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand is 3,214 MW, set on June 30, 2008, and the all-time winter peak demand is 2,527 MW, set on December 10, 2009. During these and other similarly heavy load periods Idaho Power’s system is fully committed to serve load and meet required operating reserves.
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The following table presents Idaho Power’s total power supply for the last three years:
Hydroelectric Generation:
Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generation equal to approximately 8.6 million megawatt-hours (MWh) under median water conditions.
The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is reduced.
The manner in which Idaho Power has historically optimized operation of its hydroelectric facilities may change in the future as the company is faced with integrating an increasing amount of intermittent wind generation. As additional intermittent wind generation resources are developed in the region and contracted to Idaho Power, the operational impacts will likely increase. For related information on intermittent wind generation see “Purchased Power Agreements” below.
Stream flow conditions were below average in 2010, resulting in a decrease of 0.8 million MWh generated from Idaho Power’s hydroelectric facilities compared to 2009. The observed stream flow data released in August 2010 by the U.S. Army Corps of Engineers indicated that Brownlee Reservoir inflow for April through July 2010 was 4.6 million acre-feet (maf), or 73 percent of the National Weather Service Northwest River Forecast Center (NWRFC) average, compared to 5.6 maf, or 89 percent, of the NWRFC average in 2009.
Power generation at the Idaho Power hydroelectric power plants on the Snake River also depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River. For more information on water management issues see Part II, Item 7 - “MD&A - Legal Matters - Snake River Basin Water Rights.”
Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” and is subject to regulation by the FERC. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectric projects are subject to conditions described in the FPA and related FERC regulations. These conditions and regulations include provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages, and other matters.
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Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental issues. The licenses last 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects. For further information on relicensing activities see Part II, Item 7 - “MD&A - Relicensing of Hydroelectric Projects.”
The state of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state. Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities are subject to the Oregon Hydroelectric Act. Idaho Power has obtained Oregon licenses for these facilities.
Coal and Natural Gas-Fired Generation:
Idaho Power co-owns three coal-fired power plants and owns two natural gas-fired combustion turbine power plants. The coal-fired plants are Jim Bridger located in Wyoming, Boardman located in Oregon, and Valmy located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The Langley Gulch natural gas-fired combined cycle power plant located in Idaho is currently under construction and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012.
Fuel supply-coal
Idaho Power, through its subsidiary IERCo, owns a one-third interest in BCC, which owns the Jim Bridger mine that supplies coal to the Jim Bridger generating plant (one-third owned by Idaho Power). The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2024 from surface, high-wall, and underground sources. Idaho Power believes that the Jim Bridger mine has sufficient reserves to provide coal deliveries for the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2014 from the Black Butte Coal Company’s Black Butte and Leucite Hills mines located near the Jim Bridger plant. This contract supplements the Bridger Coal deliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train provide the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.
NV Energy, Inc., as the operator of the Valmy generating plant, has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant through 2011; however, due to force majeure provisions of the contract, approximately 131,000 tons (Idaho Power portion) will be delivered to the Valmy plant in 2012 instead of 2011. As a 50 percent owner of the plant, Idaho Power is obligated to purchase one-half of the coal, ranging from 515,000 tons to 762,500 tons annually. NV Energy, Inc. also has a coal supply contract with Black Butte Coal Company’s Black Butte Mine for deliveries through 2015. Idaho Power is obligated to purchase one-half of the coal purchased under this agreement ranging from as low as 44,000 to as high as 500,000 tons annually.
The Boardman generating plant receives coal from the Powder River Basin through annual contracts. Portland General Electric Company, as the operator of the Boardman plant, has two agreements with Alpha Natural Resources, Inc., to supply all of the Boardman plant’s coal requirements in 2011. As a ten percent owner of the plant, Idaho Power is obligated to purchase ten percent of the coal purchased under these agreements, which is 243,600 tons in 2011 (including approximately 60,300 tons provided by force majeure contract provisions from 2009). A request for proposal (RFP) for the 2012 coal supply is planned in 2011.
Fuel supply-natural gas
Idaho Power owns and operates the Danskin and Bennett Mountain combustion turbines. Natural gas is purchased based on system requirements. The natural gas is supplied through Northwest Pipeline GP’s (Northwest) pipeline under a 24,523 million British thermal units (MMBtu) per day long-term gas transportation service agreement. The agreement runs into 2022, with extensions at Idaho Power’s discretion. In addition to the long-term gas transportation service agreement, Idaho Power has entered into a long-term storage service agreement with Northwest for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. As the project is developed, storage capacity will be phased into service and allocated to Idaho Power on a monthly basis. Idaho Power's current storage allotment is approximately 74 percent of its total, and its full allotment is expected to be reached by March 2012. The firm storage
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contract expires in 2043. Natural gas will be purchased and stored with the intent of fulfilling needs as identified for summer peaks or to meet system requirements.
Procurement of gas for the Langley Gulch combined-cycle natural gas-fired power plant will be managed to meet system requirements and fueling strategies. Natural gas for Langley Gulch will be supplied through multiple Northwest long-term gas transportation service agreements totaling 31,061 MMBtu per day with a range of start dates beginning March 2011 and a range of end dates through May 2042. Idaho Power has sole discretion regarding extensions to the multiple long-term service agreements.
Purchased Power Agreements:
Idaho Power purchases power in the market, based on economics, operating reserve margins, risk limits, and unit availability, and from PURPA projects as mandated. Idaho Power seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.
Idaho Power has the following firm wholesale purchased power contracts and energy exchange agreements:
PPL Energy Plus, LLC - for 83 MW per hour during heavy load hours, to address increased demand during June, July and August. The contract term is through August 2011;
Raft River Energy I, LLC - for 13 MW (nameplate generation) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term is through April 2033;
Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon. The contract term is through 2027;
USG Oregon LLC - for 22 MW (estimated average annual output) from the to-be-constructed Neal Hot Springs #1 geothermal power plant located near Vale, Oregon. The contract term is 25 years with an option to extend. Commercial operation is expected in late 2012;
Clatskanie People’s Utility - for the exchange of up to 18 MW of energy from the Arrowrock Project in southern Idaho for energy from Idaho Power’s system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is January 1, 2010 through December 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms; and
NV Energy, Inc. - for the exchange of up to 45 MW of energy hourly. The agreement expires March 31, 2012.
Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions have each issued orders and rules regulating Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. A key component of the PURPA contracts is the energy price contained within the agreements. The PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The Published Avoided Cost is a price established by the IPUC and OPUC to estimate Idaho Power’s cost of developing additional generation resources. The IPUC and OPUC have established specific rules and regulations to calculate the Published Avoided Cost that Idaho Power is required to include in PURPA contracts.
Idaho Power has contracts for the purchase of energy from a number of private developers. For these contracts:
Idaho Power is required to purchase all of the output from the facilities located inside its service territory, subject to some exceptions such as adverse impacts on system reliability;
Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive power at the facility’s requested point of delivery on the Idaho Power system;
the IPUC jurisdictional portion of the costs associated with CSPP contracts is fully recovered through base rates and the PCA; the OPUC jurisdictional portion is recovered through general rate case filings and the Oregon PCA mechanism;
for IPUC jurisdictional contracts, projects that generate up to ten average MW of energy monthly are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The IPUC has granted a temporary reduction in the upper eligibility limit to 100 kilowatts (kW) for wind and solar projects, as discussed below;
for OPUC jurisdictional contracts, projects with a nameplate rating of up to ten MW of capacity are eligible for OPUC Published Avoided Costs for up to a 20-year contract term; and
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if a PURPA project does not qualify for Published Avoided Costs, Idaho Power is required to negotiate the terms, prices, and conditions with the developer. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location, and size) and the benefits to the Idaho Power system and must be consistent with other similar energy alternatives.
Published Avoided Cost rates remain relatively high, providing a favorable climate for PURPA project development, which may result in Idaho Power acquiring energy at above wholesale market prices when a surplus already exists and may also require additional integration costs, thus increasing costs to its customers. In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap, effective retroactively to December 14, 2010, to 100 kW for wind and solar PURPA projects only, while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher Published Avoided Cost rates, tax incentives, and other benefits.
As of December 31, 2010, Idaho Power had the following signed CSPP-related agreements originally ranging from one to 35 years. The majority of the new facilities will be wind resources which will generate on an intermittent basis.
During 2010, Idaho Power purchased 910,429 MWh of power from CSPP facilities at a cost of $55 million, resulting in a blended price of $60.38 per MWh.
Transmission Services
Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located anywhere from a few miles to hundreds of miles from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy, Inc. These interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among all major electric systems in the west interconnecting with the winter-peaking northern and summer-peaking southern regions of the western power system. Idaho Power provides wholesale transmission service and provides firm and non-firm wheeling services for eligible transmission customers. Idaho Power is a member of the WECC, the Western Systems Power Pool, the Northwest Power Pool, the Northern Tier Transmission Group, and the North American Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the western grid.
Resource Planning and Renewable Energy Projects
Idaho Power filed its 2009 Integrated Resource Plan (IRP) with the IPUC and OPUC in December 2009. The IRP forecasts Idaho Power’s load and resource situation for the next 20 years, analyzes potential supply-side and demand-side options, and identifies near-term and long-term actions. The 2009 IRP was accepted by the IPUC in August 2010 and acknowledged by the OPUC in October 2010. The four primary goals of the IRP are to:
identify sufficient resources to reliably serve the growing demand for energy within Idaho Power’s service area throughout the 20-year planning period;
ensure the selected resource portfolio balances cost, risk, and environmental concerns;
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give equal and balanced treatment to both supply-side resources and demand-side measures; and
involve the public in the planning process in a meaningful way.
Idaho Power updates the IRP every two years and work on the 2011 IRP began in the summer of 2010. The updated plan is expected to be completed and filed in June 2011. During the time between resource plan filings, the public and regulatory oversight of the activities identified in the 2009 IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect changes in technology, economic conditions, anticipated resource development, and regulatory requirements.
The 2009 IRP identified the 300 MW Langley Gulch project currently under construction and a 50 MW expansion of the Shoshone Falls hydroelectric facility that is currently being evaluated for economic viability. Idaho Power is also planning the Boardman to Hemingway and the Gateway West transmission lines and has constructed the Hemingway substation, all of which are intended to improve reliability, relieve congestion, and provide system flexibility. Refer to Part II, Item 7 - “MD&A - Liquidity and Capital Resources - Capital Requirements - Major Projects” for additional information about Idaho Power’s significant infrastructure development projects and plan. The 2009 IRP also included discussion related to the following resources:
Geothermal RFPs:
Although the results of previously conducted geothermal RFP processes have been disappointing, Idaho Power continues to work with project developers capable of delivering energy to the company’s service area. The 2009 IRP included two 20-MW increments of geothermal energy in the preferred portfolio; one in 2012 and one in 2016. The 20-MW increment in 2012 was addressed by a long-term power purchase agreement for the output from the Neal Hot Springs Geothermal Project located in eastern Oregon. The need for the additional 2016 increment of geothermal energy is being assessed in the 2011 IRP.
Wind RFP:
In May 2009, Idaho Power issued an RFP seeking to purchase up to 150 MW of wind generation by 2012. The RFP generated considerable interest from wind developers, and throughout the first half of 2010, Idaho Power negotiated with the front-runner. During this time, other project developers began expressing an interest in developing wind projects under PURPA and it became evident the additional wind generation under PURPA would exceed the 150 MW identified in the RFP. Due to the acquisition of this additional PURPA wind generation and due to stalled contract negotiations in the RFP process, Idaho Power did not award a contract under the RFP process and concluded the RFP process in August 2010.
Combined Heat and Power (CHP) RFP:
CHP resources were not included in the 2009 IRP preferred portfolio because of the uncertainty in being able to successfully develop a CHP project. However, Idaho Power continues to work with large customers and other parties to explore CHP development opportunities.
In 2009, Idaho Power signed an agreement to jointly investigate a CHP project with the Idaho Office of Energy Resources (IOER) and The Amalgamated Sugar Company (TASCO), one of Idaho Power’s large industrial customers. The agreement established the framework for a high-level feasibility study to investigate installing a CHP project at TASCO’s Nampa, Idaho facility that could be as large as 100 MW. The IOER and Idaho Power jointly funded the study. The high-level feasibility study confirmed initial estimates of the project’s potential benefits, and in September 2010, Idaho Power, IOER, and TASCO entered into a second agreement to complete a more detailed feasibility study to refine performance and financial modeling of the proposed project. An RFP was issued and a consulting firm was selected to perform the more detailed feasibility study. The study is expected to be completed by the second quarter of 2011.
Energy Efficiency and Demand-Side Management Programs:
In 2010, Idaho Power’s energy efficiency programs reduced energy usage by approximately 170,000 MWh, and the demand response programs resulted in a summer peak demand reduction of about 300 MW through combined program performance.
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In 2010, Idaho Power spent approximately $45.6 million on energy efficiency and targeted demand reduction response programs. Approximately $44.2 million of funding for these programs is funded by Idaho and Oregon energy efficiency tariff riders while the balance of the funding comes from Idaho Power base rates.
Idaho Power has 15 energy efficiency and demand response programs in place, targeting savings across the entire year and summer system demand reduction. These programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimize or delay the need for new infrastructure. Idaho Power’s programs include:
financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
energy efficiency for new and existing homes, including efficient appliances and HVAC equipment, energy efficient building techniques, insulation improvement, air duct sealing, and energy efficient lighting;
incentives to industrial and commercial customers for using energy efficient equipment, and using energy efficiency techniques and operational and management processes; and
demand response programs to reduce peak summer demand through the voluntary interruption of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through a third-party demand response aggregator.
Approximately $3 million of Idaho Power’s 2010 energy efficiency spending was related to research and analysis, education, technology evaluation, and market transformation. Most of this activity was done in conjunction with the Northwest Energy Efficiency Alliance (NEEA).
Environmental Regulation
Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment including air, water, and solid waste. Current and pending legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards (RES), mercury and other emissions, hazardous wastes, and polychlorinated biphenyls (PCBs). Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power discontinue operating certain power generation plants. Environmental regulation continues to impact Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with such regulations, and the modification of system operations to accommodate such regulations. In addition to generally applicable regulations, the FERC licenses issued for Idaho Power’s hydroelectric generating plants have environmental requirements such as aeration of turbine water to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies. Further, Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation. For a more detailed discussion of these and other environmental issues, refer to Part II, Item 7 - “MD&A - Environmental Issues.”
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Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future, especially with potential additional regulation under discussion at the state and federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding allowance for funds used during construction (AFUDC) (in millions of dollars):
Idaho Power anticipates that a number of impending EPA rulemakings and proceedings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs.
IFS
IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS generated tax credits of $7 million, $8 million, and $11 million in 2010, 2009, and 2008, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS had $7 million, $14 million, and $8 million of new investments during 2010, 2009, and 2008, respectively, and will continue to review future legislation for new opportunities for investment that will be commensurate with the ongoing needs of IDACORP.
IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk. Over 90 percent of IFS’s investments have been made through syndicated funds. At December 31, 2010, the gross amount of IFS’s portfolio equaled $204 million in tax credit investments. These investments cover 49 states, Puerto Rico, and the U.S. Virgin Islands. The underlying investments include over 700 individual properties, of which all but six are administered through syndicated funds.
IDA-WEST
Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $8 million, $9 million, and $8 million in 2010, 2009, and 2008, respectively.
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EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below, along with their business experience during at least the past five years. Mr. J. LaMont Keen and Mr. Steven R. Keen are brothers. There are no other family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was elected.
J. LAMONT KEEN, 58
President and Chief Executive Officer of IDACORP, Inc., July 1, 2006 - present.
President and Chief Executive Officer of Idaho Power Company, November 17, 2005 - present.
	Executive Vice President of IDACORP, Inc., March 1, 2002 - July 1, 2006.
Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company. 	
DARREL T. ANDERSON, 52
Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, October 1, 2009 - present.
Senior Vice President - Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, July 1, 2004 - October 1, 2009.
DANIEL B. MINOR, 53
• Executive Vice President of IDACORP, Inc., May 20, 2010 - present.
• Executive Vice President, Operations of Idaho Power Company, October 1, 2009 - present.
• Senior Vice President - Delivery of Idaho Power Company, July 1, 2004 - October 1, 2009.
REX BLACKBURN, 55
• Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power Company, April 1, 2009 - present.
• Lead Counsel of Idaho Power Company, January 1, 2008 - March 31, 2009.
• Partner at Blackburn and Jones, LLP, a law firm, January 2003 - December 31, 2007.
LISA A. GROW, 45
• Senior Vice President, Power Supply of Idaho Power Company, October 1, 2009 - present.
• Vice President - Delivery Engineering and Operations of Idaho Power Company, July 20, 2005 - September 30, 2009.
STEVEN R. KEEN, 50
• Vice President, Finance and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2010 - present.
• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 - May 31, 2010.
• President of IDACORP Financial Services, September 1998 - May 31, 2007.
PATRICK A. HARRINGTON, 50
• Corporate Secretary of IDACORP, Inc. and Idaho Power Company, March 15, 2007 - present.
• Senior Attorney, IDACORP, Inc. and Idaho Power Company, June 2003 - March 15, 2007.
DENNIS C. GRIBBLE, 58
• Vice President and Chief Information Officer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 - present.
• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, July 2004 - June 1, 2006.
LORI D. SMITH, 50
Vice President, Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
Vice President - Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2008 - May 20, 2010.
Vice President - Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, July 2004 - January 1, 2008.
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LUCI K. MCDONALD, 53
• Vice President, Human Resources and Corporate Services of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
• Vice President - Human Resources of IDACORP, Inc. and Idaho Power Company, December 2004 - May 20, 2010.
NAOMI SHANKEL, 39
• Vice President, Supply Chain of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
• Vice President, Audit and Compliance of IDACORP, Inc. and Idaho Power Company, September 21, 2006 - May 20, 2010.
• Director, Audit Services of IDACORP, Inc. and Idaho Power Company, July 2003 - September 21, 2006.
JEFFREY MALMEN, 43
• Vice President, Public Affairs of IDACORP, Inc. and Idaho Power Company, October 1, 2008 - present.
• Senior Manager - Governmental Affairs of IDACORP, Inc. and Idaho Power Company, December 2007 - October 1, 2008.
• Chief of Staff of the Office of Idaho Governor C.L. “Butch” Otter, January 2007 - November 2007.
• Chief of Staff of the Office of Idaho Congressman C.L. “Butch” Otter, January 2001 - December 2006.
JOHN R. GALE, 60
• Sr. Vice President, Corporate Responsibility of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
• Vice President - Regulatory Affairs of Idaho Power Company, March 2001 - May 20, 2010.
WARREN KLINE, 55
• Vice President, Customer Operations of Idaho Power Company, May 20, 2010 - present.
• Vice President - Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 - May 20, 2010.
N. VERN PORTER, 51
• Vice President, Delivery Engineering and Operations, Idaho Power Company, October 1, 2009 - present.
• General Manager of Power Production of Idaho Power Company, April 22, 2006 - October 1, 2009.
• Senior Manager of Power Supply Operations of Idaho Power Company, August 2003 - April 22, 2006.
KEN W. PETERSEN, 47
• Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
• Corporate Controller of IDACORP and Idaho Power Company, December 29, 2007 - May 20, 2010.
• General Manager Delivery Services and Delivery Business Unit Controller of Idaho Power Company, January 2004 - December 28, 2007.
GREGORY W. SAID, 56
• Vice President, Regulatory Affairs, Idaho Power Company, January 20, 2011 - present.
• General Manager of Regulatory Affairs, Idaho Power Company, April 3, 2010 - January 20, 2011.
• Director, State Regulation, Idaho Power Company, August 23, 2008 - April 3, 2010.
• Manager, Revenue Requirement, Idaho Power Company, November 14, 1998 - August 23, 2008.
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ITEM 1A.
ITEM 1A. RISK FACTORS
In addition to the factors discussed elsewhere in this report, the risk factors set forth below may have a significant impact on the business, financial condition, or results of operations of IDACORP, Inc. and Idaho Power Company and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements.
If the Idaho Public Utilities Commission, the Oregon Public Utility Commission, or the Federal Energy Regulatory Commission grant less rate recovery in regulatory proceedings than Idaho Power Company needs to cover existing and future increased costs of providing services, earnings and cash flows may be reduced. The prices that the Idaho Public Utilities Commission and Oregon Public Utility Commission authorize Idaho Power Company to charge for its retail services, and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power Company to charge for transmission, are the most significant factors influencing IDACORP, Inc.’s and Idaho Power Company’s financial position, results of operations, and liquidity. The Idaho Public Utilities Commission and Oregon Public Utility Commission have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the formula rates allowed by the Federal Energy Regulatory Commission may be insufficient for recovery of costs incurred. While the Idaho Public Utilities Commission and Oregon Public Utility Commission have established through the ratemaking process an authorized rate of return for Idaho Power Company, the regulatory process does not provide assurance that Idaho Power Company will be able to achieve the earnings level authorized. Further, while the Idaho Public Utilities Commission and Oregon Public Utility Commission are required to establish rates that are fair, just, and reasonable, they have significant discretion in applying this standard. The ratemaking process typically involves multiple parties, including governmental bodies, consumer advocacy groups, and various consumers of energy, each party has differing concerns but have the common objective of limiting rate increases or even reducing rates. Idaho Power Company cannot predict the ultimate outcomes of any ratemaking proceedings, including the extent to which certain costs-such as significant capital projects-will be recovered or what rates of return will be allowed.
In January 2010, the Idaho Public Utilities Commission approved a settlement agreement that imposed a general rate moratorium in effect in the Idaho jurisdiction until January 1, 2012. While the moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment, the fixed cost adjustment, pension funding, advanced metering infrastructure, energy efficiency rider, and government imposed fees, Idaho Power Company attempts to manage its costs consistent with the moratorium. However, if Idaho Power Company is unable to do so, or if such cost management results in increased operational risk, the moratorium could adversely affect Idaho Power Company’s operations or results of operations.
Idaho Power Company has power cost adjustment mechanisms that provide for periodic adjustments to the rates charged to its Idaho and Oregon retail customers. The power cost adjustment tracks Idaho Power Company’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. A majority, but not all, of the variance between these two amounts is deferred for future recovery from or refund to customers. Accordingly, the power cost adjustment mechanism only partially offsets the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydroelectric generating availability, and volatile wholesale energy prices. Because of the power cost adjustment mechanism, the primary financial impact of power supply cost variations is on the timing of cash flows. When costs rise above the level recovered in retail rates it adversely affects Idaho Power Company’s operating cash flow and liquidity until those costs are recovered from customers.
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Reduced hydroelectric generation can reduce revenues and increase costs, and reduce earnings and cash flows. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company’s heavy reliance on hydroelectric generation, the availability of water can significantly affect its operations. When hydroelectric generation is reduced, Idaho Power Company must increase its use of generally more expensive thermal generating resources and purchased power and opportunities for off-system sales are reduced, which reduces revenues. In addition, while Idaho Power Company can expect to recover, as a result of its power cost adjustment mechanisms, the majority of its net power supply costs above the level included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year.
Continuing declines in stream flows and over-appropriation of water in Idaho may reduce hydroelectric generation and revenues and increase costs. The combination of declining Snake River base flows, over-appropriation of water, and drought conditions have led to disputes among surface water and ground water irrigators, and the State of Idaho. Recharging the Eastern Snake Plain aquifer, which contributes to Snake River flows, by diverting surface water to porous locations and permitting it to sink into the aquifer, is one proposed solution to the dispute. Diversions from the Snake River for aquifer recharge may further reduce Snake River flows available for hydroelectric generation and reduce Idaho Power Company’s revenues and increase costs. Idaho Power Company’s January 2010 settlement agreement with the State of Idaho resolves litigation regarding certain Idaho Power Company water rights on the Snake River and provides for ongoing Snake River water issues to be addressed in a comprehensive aquifer management plan process. However, there is no assurance that this process will lead to increased Snake River stream flows for Idaho Power Company’s hydroelectric projects. Idaho Power Company also has initiated legal action against the U.S. Bureau of Reclamation over the interpretation and effect of a 1923 contract with the U.S. Bureau of Reclamation on the operation of the American Falls Reservoir and the release of water from that reservoir to be used at Idaho Power Company’s downstream hydroelectric projects. The comprehensive aquifer management plan process and the resolution of the litigation may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power Company’s revenues and increase costs.
Idaho Power Company’s reliance on coal and natural gas to fuel its power generation facilities exposes it to risk of increased costs and reduced earnings. In addition to hydroelectric generation, Idaho Power Company relies on coal and natural gas to fuel its generation facilities. Increases in market prices for coal and natural gas can result in reduced earnings. Increases in demand for natural gas may result in market price increases, short-term price volatility, and supply availability issues. Operation of the Langley Gulch power plant that Idaho Power Company is currently constructing will increase Idaho Power Company’s demand for natural gas, and thus its exposure to volatility in natural gas prices. In addition, delivery of coal and natural gas depends upon gas pipelines, rail lines, rail cars, and roadways. Any disruption in Idaho Power Company’s fuel supply may require the company to find alternative fuel sources at higher costs, to produce power from higher cost generation facilities, or to purchase power from other sources at higher costs, which may adversely impact earnings.
Idaho Power Company’s power generating facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with hydroelectric, natural gas, coal, and other generation facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, regulatory compliance obligations and costs, labor disputes, workforce safety matters, and catastrophic events at the facilities. These operational risks may result in plant outages, as well as increased operation and maintenance expenses, power generation costs, and power purchase costs.
Load growth in Idaho Power Company’s service territory exposes it to greater market and operational risk and could increase costs and reduce earnings and cash flows. While Idaho Power Company’s customer growth rate has slowed in recent years, increases in both the number of customers and the demand for energy have resulted and may continue to result in increased reliance on purchased power to meet that demand. While Idaho Power Company can expect to recover the majority of the net power supply costs above the amounts included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year, and the remaining amount is absorbed by Idaho Power Company, which could increase costs and reduce earnings and cash flows. Load growth can result in the need for additional investments in Idaho Power Company’s infrastructure to serve the new load. For instance, to meet customer demand Idaho Power Company is currently constructing its Langley Gulch natural gas-fired generating plant, and has in development a number of transmission projects. If Idaho Power Company was unable to secure timely rate relief from the Idaho Public Utilities Commission, the Oregon Public Utility Commission, or the Federal Energy Regulatory Commission to recover the costs of these additional investments, the resulting disconnect between the time expenditures are made and costs are recovered would have a negative effect on earnings and cash flows. Load growth can create planning and operating difficulties for Idaho Power Company that can negatively impact its ability to reliably serve customers.
Weather and climate change could affect customer demand and hydroelectric generation and disrupt transmission and distribution systems, reducing earnings and cash flows. Warmer than normal winters, cooler than normal summers, and increased rainfall during the irrigation seasons will reduce retail revenues from power sales and may impact the amount and timing of hydroelectric generation. Extreme weather
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events can disrupt transmission and distribution systems and cause service interruptions and extended outages, increase supply chain costs, and potentially interrupt use of generation resources and limit the ability to meet customer demand. Disruption in transmission and distribution systems increases operations and maintenance expenses and reduces earnings and cash flows.
In addition, long-term climate change could affect Idaho Power Company’s business in a variety of ways, including:
• changes in temperature and precipitation could affect customer demand;
• extreme weather events could increase service interruptions, outages, and maintenance costs;
• changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation;
• legislative and/or regulatory developments related to climate change could affect plans and operations, including placing restrictions on the construction of new generation resources and the expansion of existing resources, result in closure of generation resources or installation of costly pollution control equipment, or require changes to the operation of generation resources in general; and
• consumer preference for, and resource planning decisions requiring, renewable or low greenhouse gas-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources.
Any of these effects of climate change could decrease revenues, increase operating costs, and reduce IDACORP, Inc.’s and Idaho Power Company’s earnings and cash flows.
Idaho Power Company’s risk management policy and programs relating to hedging power and gas exposures and counterparty creditworthiness may not always perform as intended, and as a result Idaho Power Company may suffer economic losses. Idaho Power Company is exposed to the risk that counterparties that owe it money will default on their obligations. A similar risk of non-performance by third parties arises where those parties are obligated to purchase energy from, or sell energy to, Idaho Power Company, or are parties to commodity price risk management arrangements. Idaho Power Company actively manages the market risk inherent in its energy related activities and counterparty credit positions. Idaho Power Company has procedures that monitor compliance with its risk management policies and programs, including verification of transactions, regular portfolio reporting of various risk management metrics, and daily counterparty credit risk analysis. However, actual hydroelectric and thermal generation, transmission availability, and market prices may be significantly different than those originally planned for when Idaho Power Company enters into its hedging transactions positions. The high volatility of these items creates uncertainty in the appropriate amount of hedging activity to pursue. Forecasts of future loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power Company to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. Changes in market prices are also unpredictable and can at times result in Idaho Power Company’s hedged positions performing less favorably than unhedged positions. In addition, Idaho Power Company’s counterparty credit policies may not prevent counterparties from failing to perform, forcing the company to replace forward contracts with transactions in the open market. As a result, risk management decisions may have significant impacts if actual events result in greater losses or costs in delivering energy to customers and could negatively affect IDACORP, Inc.’s and Idaho Power Company’s financial condition, results of operations, or cash flows.
Increased capital expenditures for power generation and delivery infrastructure development and replacement can significantly affect liquidity. Idaho Power Company’s business is capital intensive and requires significant investments in energy generation and in other infrastructure projects. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission and distribution systems, generating facilities, and other infrastructure. The cost of maintaining existing, aging equipment and infrastructure and developing new infrastructure is substantial, and involves risks relating to, among other things, cost overruns, unscheduled outages, price increases in commodities (such as steel and copper) and other materials necessary for developing infrastructure, and denial of regulatory recovery. If Idaho Power Company does not receive timely regulatory recovery of costs associated with those expansion and reinforcement activities or other capital projects, Idaho Power Company will have to rely more heavily on external financing for its future utility construction expenditures. These large planned expenditures may weaken the consolidated financial profile of IDACORP, Inc. and Idaho Power Company.
Additionally, a significant portion of Idaho Power Company’s facilities were constructed many years ago, which could affect reliability and increase maintenance costs. Failure of equipment or facilities used in Idaho Power Company’s system could potentially increase repair and maintenance expenses, purchased power expenses, and capital expenditures.
The performance of pension and postretirement benefit plan investments and other factors impacting plan costs could adversely impact cash flow and liquidity. Idaho Power Company provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plan’s assets and, therefore, adverse investment performance for these assets could increase Idaho Power Company’s funding requirements related to the plans. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future stock market performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. Depending on the timing of contributions to the plans and the availability of recovery of costs through rates, cash contributions to the plans could impact IDACORP, Inc.’s and Idaho Power Company’s cash flow and liquidity.
Complying with existing and future environmental laws and regulations will increase capital expenditures and operating costs and may reduce Idaho Power Company’s earnings and cash flows and ability to meet the electricity needs of its customers. Idaho Power Company is subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, natural resources, and health and safety. Compliance with these environmental statutes, rules, and regulations involves significant capital and operating expenditures. Members of Congress have proposed legislation to limit and reduce greenhouse gas emissions, and the Environmental Protection Agency is taking action to address climate change and regulate greenhouse gas emissions, including the adoption of new reporting requirements that apply to Idaho Power Company’s facilities. The Environmental Protection Agency has also made an “endangerment finding” for greenhouse gas emissions from motor vehicles and has indicated that the Clean Air Act will require it to regulate carbon dioxide and other greenhouse gas emissions from major stationary sources, including Idaho Power Company’s thermal facilities, once it adopts greenhouse gas emission standards for motor vehicles. The adoption of a mandatory federal program or state programs to reduce carbon dioxide and other greenhouse gas emissions would raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities. Mercury and other pollutant emissions from Idaho Power Company’s thermal facilities are also subject to extensive regulation. The adoption of new statutes, rules, and regulations to reduce emissions, including controls to reduce carbon dioxide, greenhouse gas, mercury, or other pollutant emissions will result in increased capital expenditures and could increase the cost of operating coal-fired generating plants or make them uneconomical to operate and result in reduced earnings and cash flows.
Complying with state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. A number of states have adopted renewable energy portfolio standards. Idaho Power Company’s operations in Oregon will be required to comply with a ten percent renewable energy portfolio standard beginning in 2025, and it is possible that other states could adopt renewable energy portfolio standards that are applicable to Idaho Power in the future. New state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows.
The listing as threatened or endangered under the Endangered Species Act of fish, wildlife, or plant species that are found in the areas of Idaho Power Company’s generation facilities or transmission lines may require mitigation, affect the location of a project or the ability to construct a project, and result in increased capital expenditures and operating costs. Relicensing of the Hells Canyon and Swan Falls hydroelectric projects and the construction of the Langley Gulch power plant and the Gateway West and Boardman to Hemingway transmission lines require consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas. The recent listing of
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slickspot peppergrass as a threatened species will require an Endangered Species Act consultation for the transmission and water lines for Langley Gulch as well as for the Gateway West and Boardman to Hemingway transmission lines, and future transmission projects. Similarly, the presence of sage grouse in the vicinity of Idaho Power’s Boardman to Hemingway and Gateway West 500-kV transmission line projects has required more extensive, costly, and time consuming evaluation and engineering. The impact of the Endangered Species Act, including the potential listing of additional fish, wildlife, or plant species, and similar laws may require mitigation, cause a delay in relicensing or construction of projects, affect the location or ability to construct a project, increase the costs of construction and operations, and reduce earnings and cash flows.
Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric production, and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for some of its hydroelectric projects, including its largest hydroelectric generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The listing of various species of marine life, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon and other marine life recovery plans could include further major operational changes to the region’s hydroelectric projects. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power Company’s energy requirements.
In 2007, the Federal Energy Regulatory Commission Staff issued a final environmental impact statement for the Hells Canyon Complex, which the Federal Energy Regulatory Commission will use in part to determine whether, and under what conditions, to issue a new license for the Hells Canyon Complex. Certain portions of the final environmental impact statement involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act and formal consultations under the Endangered Species Act, which remain unresolved. One significant issue involves water temperature gradients, and certain parties in the Hells Canyon Complex relicensing proceedings have advocated for the installation of water temperature management apparatus which, if required to be installed, would require substantial capital expenditures to construct and maintain. There can be no assurance that recovery through rates would be authorized, particularly given the magnitude of any potential impact on customer rates, which at this time cannot be accurately predicted. Idaho Power Company also cannot predict the requirements that might be imposed during the relicensing process, the economic impact of those requirements, or whether a new multi-year license will ultimately be issued. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs, and reduce hydroelectric generation, which could reduce earnings and cash flows.
Idaho Power Company’s business is subject to substantial governmental regulation and may be adversely affected by increased costs resulting from, or liability under, existing or future regulations or requirements. Idaho Power Company is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, and the public utility commissions in Idaho, Oregon, and Wyoming. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences. Idaho Power Company has self-reported compliance issues to the Federal Energy Regulatory Commission and to the Western Electricity Coordinating Council. Several of the matters self-reported to the Federal Energy Regulatory Commission and the Western Electricity Coordinating Council remain outstanding. Compliance with these requirements directly influences Idaho Power Company’s operating environment and may significantly increase Idaho Power Company’s operating costs. Further, potential monetary and non-monetary penalties for a violation of Federal Energy Regulatory Commission regulations may be substantial, and in some circumstances monetary penalties may be as high as $1 million per day per violation. The imposition of penalties on Idaho Power Company could have an adverse impact on its and IDACORP, Inc.’s results of operations, financial condition, and cash flows.
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IDACORP, Inc., its subsidiary IDACORP Energy, and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations, and claims. IDACORP, Inc., IDACORP Energy, and Idaho Power Company are involved in a number of proceedings, including the California refund proceeding, a portion of which remains pending before the Federal Energy Regulatory Commission and the United States Court of Appeals for the Ninth Circuit; a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest; and show cause proceedings originating at the Federal Energy Regulatory Commission, a portion of which remains pending in the United States Court of Appeals for the Ninth Circuit. It is possible that additional proceedings related to the western energy situation may be filed in the future against IDACORP, Inc., IDACORP Energy, or Idaho Power Company. IDACORP, Inc. and Idaho Power Company are or may also be subject to costs and other effects of additional legal claims, actions, and complaints, including those related to the Jim Bridger, Valmy, and Boardman coal-fired plants, in which Idaho Power Company holds an ownership interest. For instance, in September 2010, the Environmental Protection Agency issued a Notice of Violation to Portland General Electric Company, the majority owner of the Boardman plant, alleging that Portland General Electric Company had violated the New Source Performance Standards and operating permit requirements under the Clean Air Act, as a result of modifications made to the plant in 1998 and 2004. State attorneys general have brought actions against companies seeking additional disclosure of climate change-related risks and impacts, and private parties have brought tort actions against companies relating to their alleged contribution to climate change. If IDACORP, Inc., IDACORP Energy, or Idaho Power Company are required to make payments in connection with any legal or regulatory proceeding, settlement, investigation, or claim, earnings and cash flows could be negatively affected.
As a holding company, IDACORP, Inc. does not have its own operating income and must rely on the upstream cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP, Inc. is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power Company. Consequently, IDACORP, Inc.’s ability to pay dividends and to service its debt is dependent upon dividends and other payments received from its subsidiaries. IDACORP, Inc.’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, Inc., whether through dividends, loans, or other payments. The ability of IDACORP, Inc.’s subsidiaries to pay dividends or make distributions to IDACORP, Inc. depends on several factors, including each subsidiaries’ actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities.
A downgrade in IDACORP, Inc.’s and Idaho Power Company’s credit ratings could negatively affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP, Inc. and Idaho Power Company. IDACORP, Inc. and Idaho Power Company also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper. Downgrades of IDACORP, Inc.’s or Idaho Power Company’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access capital, including the commercial paper markets, require the companies to pay a higher interest rate on their debt, and require the companies to post collateral with transaction counterparties.
Volatility in the financial markets may negatively affect IDACORP, Inc.’s and Idaho Power Company’s ability to access capital and/or increase their cost of borrowing, or result in losses on investments. IDACORP, Inc. and Idaho Power Company require liquidity to pay operating expenses and principal of and interest on debt and to finance capital expenditures not satisfied by cash flows from operations. Financial markets have in recent years experienced extreme volatility and disruption, generally resulting in a decrease in the availability of liquidity and credit for borrowers. In a volatile credit environment, one or more of the participating banks in IDACORP, Inc.’s and Idaho Power Company’s credit facilities may default on their obligations to make loans under, or withdraw from, the credit facilities, or IDACORP, Inc.’s and Idaho Power Company’s access to capital may otherwise be inhibited. In addition, at times Idaho Power Company has a relatively large balance of short-term investments, particularly during times when it has issued debt or equity securities to fund future debt maturities not yet due and capital expenditure requirements payable over time. Volatility in the financial markets may result in a lack of liquidity for short-term investments and declines in value of some investments. The occurrence of any of these events could adversely affect IDACORP, Inc.’s and Idaho Power Company’s earnings, liquidity, and financial condition.
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National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows. Recent concerns over energy costs, the availability and cost of credit, declining business, and high rates of unemployment contributed to a recent recession. These factors have resulted, and may continue to result, in an increase in late payments and uncollectible accounts, which reduce IDACORP Inc.’s and Idaho Power Company’s earnings and cash flows.
National and regional economic conditions, in conjunction with increased electric rates, may reduce energy consumption, which may reduce revenues and future growth. Beginning in 2008, economic conditions in Idaho Power Company’s service area have been relatively weak. Unemployment rates are high relative to historic unemployment levels and customer growth has been slow relative to prior years. The recent recession and increased rates may reduce the amount of energy Idaho Power Company’s customers consume, result in a loss of customers, and reduce the customer growth rate. A decrease in overall customer usage may reduce revenues, earnings, and future growth.
Changes in tax laws and regulations, or differing interpretation or enforcement of applicable laws by the Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP, Inc.’s or Idaho Power Company’s financial condition. IDACORP, Inc. and Idaho Power Company must make judgments and interpretations about the application of the law when determining the provision for taxes. The companies’ tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation, and employment-related taxes and ongoing issues related to these taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by taxing authorities. For instance, in September 2010, Idaho Power Company adopted a tax accounting method change for repair-related expenditures on utility assets concurrent with the filing of IDACORP, Inc.’s 2009 consolidated federal income tax return. Also in the third quarter of 2010, Idaho Power Company reached an agreement with the Internal Revenue Service, subject to subsequent review by the U.S. Congress Joint Committee on Taxation, regarding the allocation of mixed service costs in its method of uniform capitalization. The outcome of ongoing and future income tax proceedings such as these could differ materially from the amounts currently recorded, and the difference could reduce IDACORP, Inc.’s and Idaho Power Company’s earnings and cash flows. Further, in some instances the treatment from a ratemaking perspective of any benefits from tax-related projects, or the reversal of reserves recorded by IDACORP, Inc. or Idaho Power Company for tax-related matters such as those described above, could be different than IDACORP, Inc. or Idaho Power Company currently anticipate or in the future request from the regulatory bodies. The Idaho Public Utilities Commission or Oregon Public Utility Commission could, for instance, determine that all or a portion of any benefits resulting from tax-related projects be shared with customers in the form of reduced rates or otherwise, which may reduce revenue, earnings, and cash flows.
Employee workforce factors could increase costs and reduce earnings. Idaho Power Company is subject to workforce factors, including, but not limited to, loss or retirement of key personnel, availability of qualified personnel, an aging workforce, and impacts of efforts to organize workforce, including the possible unionization of one or more segments of the workforce. Idaho Power Company’s operations require a skilled workforce to perform specialized, complex utility functions. Idaho Power Company expects that a significant portion of its skilled workforce will be retiring within the coming decade, which places demand on Idaho Power Company to attract and retain skilled workers. Without a skilled workforce, Idaho Power Company’s ability to provide quality service to its customers and meet regulatory requirements will be challenged and could affect earnings. Also, the costs associated with attracting and retaining appropriately qualified employees to replace an aging workforce could reduce earnings and cash flows.
Terrorist threats and activities could result in reduced revenues and increased costs. Idaho Power Company’s generation and transmission facilities are potential targets for terrorist threats and activities. The possibility that infrastructure facilities, such as fossil and hydroelectric generation facilities and electric transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror may affect Idaho Power Company’s operations. Instability in the financial markets as a result of terrorism, war, and similar actions may also affect Idaho Power Company’s results of operations and its ability to raise capital. Further, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased compliance costs.
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IDACORP, Inc. and Idaho Power Company could be vulnerable to security breaches or other similar events that could disrupt their operations, require significant capital expenditures, and/or result in claims against the companies. In the normal course of business, Idaho Power Company collects, processes, and retains sensitive and confidential customer and proprietary information, and operates systems that directly impact the availability of electric power and the transmission of electric power in the electric grid. Despite the security measures in place, Idaho Power Company’s facilities and systems, and those of third-party service providers, could be vulnerable to security breaches or other similar events that could interrupt operations, resulting in a shutdown of service and expose Idaho Power Company to liability. In addition, Idaho Power Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.
Idaho Power Company’s ability to enter into over-the-counter derivatives and hedge commodity and interest rate risk may be adversely affected by recent federal legislation. In July 2010, Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act. Title VII of the legislation provides for the regulation of the over-the-counter derivatives market, and requires the posting of cash collateral for uncleared swaps. If the rules enacted under the legislation require that Idaho Power Company post cash collateral on its swap or derivative transactions, its liquidity may be adversely affected, and rules promulgated under the legislation may impair Idaho Power Company’s ability to enter into over-the-counter derivatives to hedge commodity and interest rate risks.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 2.
ITEM 2. PROPERTIES
Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, two natural gas-fired plants located in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. Idaho Power is also constructing a natural gas-fired combined cycle power plant in Idaho with a summer nameplate capacity of 300 MW. As of December 31, 2010, the system also includes approximately 4,817 pole miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 228 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 26,698 pole miles of distribution lines.
Idaho Power holds FERC licenses for all of its hydroelectric projects that are subject to federal licensing. These projects and the other generating stations and their nameplate capacities are listed below:
Relicensing of Idaho Power’s hydroelectric projects is discussed in Part II, Item 7 - “MD&A - Relicensing of Hydroelectric Projects.”
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Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the FPA and reservoirs and other easements. Idaho Power’s property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, Idaho Power’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, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition.
IERCo owns a one-third interest in BCC and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant.
Ida-West holds 50 percent interests in nine operating hydroelectric plants with a total generating capacity of 45 MW. These plants are located in Idaho and California.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Please see Note 10 - “Contingencies” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report.
ITEM 4.
ITEM 4. (Reserved)
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE). On February 17, 2011, there were 13,132 holders of record of IDACORP common stock and the closing stock price was $38.04 per share. The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.
The amount and timing of dividends paid 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 current and long-term financial position and results of operations, capital requirements, rating agency requirements, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power 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 Idaho Power.
A covenant under IDACORP’s credit facility and Idaho Power’s credit facility described in Part II, Item 7 - “MD&A - Liquidity and Capital Resources - Financing Programs - Credit Facilities” requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined in the respective credit facilities, of no more than 65 percent at the end of each fiscal quarter.
Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct. At December 31, 2010, the leverage ratios for IDACORP and Idaho Power were 52 percent and 53 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $628 million and $538 million, respectively, at December 31, 2010. Idaho Power must obtain approval of the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
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Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding. IDACORP and Idaho Power paid dividends of $58 million, $57 million, and $54 million in 2010, 2009, and 2008, respectively.
The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2010 and 2009 as reported in the NYSE’s consolidated transaction reporting system.
IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2010.
Performance Graph
The following performance graph shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index and the Edison Electric Institute (EEI) Electric Utilities Index. The data assumes that $100 was invested on December 31, 2005, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and EEI
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The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and should not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
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In the second quarter of 2006, IDACORP management designated the operations of two subsidiaries, IDACORP Technologies, Inc. and IDACOMM, Inc., as assets held for sale, and the companies were sold in July 2006 and February 2007, respectively. IDACORP’s consolidated financial statements reflect the reclassification of the results of these businesses as discontinued operations for all periods presented. Beginning January 1, 2009, noncontrolling interests (previously known as minority interests) were required to be classified as equity. IDACORP’s consolidated financial statements reflect the reclassification of noncontrolling interests to equity for all periods presented.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Megawatt-hours and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.)
FORWARD-LOOKING STATEMENTS
In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations and, as such, constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. 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,” “targets,” “plans,” “predicts,” projects,” “may result,” “may continue,” or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from those expressed in or implied by those forward-looking statements. For a discussion of some of the specific factors that may cause IDACORP, Inc.’s and Idaho Power Company’s actual results to differ materially from those projected in any forward-looking statements, see the following sections of this report: Part I, Item 1A - “Risk Factors”; Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” including the disclosures under “Critical Accounting Policies and Estimates”; and Notes 2, 11, and 15 to the Consolidated Financial Statements in Part II, Item 8 - “Financial Statements and Supplementary Data.”
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. IDACORP, Inc. and Idaho Power Company disclaim any intention or obligation to update publicly any forward-looking statements, whether in response to new information, future events, or otherwise, except as required by applicable law.
INTRODUCTION
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) presents the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power).
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.”
Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 492,000 general business customers as of December 31, 2010. Idaho Power is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
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Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territory, as well as from wholesale electricity sales and transmission of electricity for others. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions, through which Idaho Power seeks to recover its costs on a timely basis and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.
IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act (PURPA); and IDACORP Energy, a marketer of energy commodities that wound down operations in 2003.
While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power which present for each company their financial positions at December 31, 2010 and 2009, and their results of operations and cash flows for the years ended December 31, 2010, 2009, and 2008.
EXECUTIVE OVERVIEW
Business Strategy
IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power has a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power’s business strategy seeks to balance the interest of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet population and electricity demand growth. Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources Idaho Power and the communities the company serves depend upon. Idaho Power’s business strategy also includes the use of energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standard (RPS) legislation, and targeted reductions relating to carbon emission intensity and public reporting of these reductions.
Overview of Major Factors Affecting Results of Operations and Financial Condition
IDACORP and Idaho Power’s results of operations and financial condition are affected, and will likely continue to be affected, by important business, regulatory, economic, and other factors, as discussed below.
Regulatory Framework, Rates, and Cost Recovery: Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, and has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. The prices that the IPUC and OPUC authorize Idaho Power to charge for its retail services and the tariff rate that the FERC permits Idaho Power to charge for transmission are major factors in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The IPUC and OPUC have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the FERC formula rates may be insufficient for recovery of actual costs incurred. While the IPUC and OPUC have established, through the ratemaking process, an authorized rate of return for Idaho Power, the regulatory process does not provide assurance that Idaho Power will be able to achieve the authorized rate. Further, while the IPUC and OPUC are required to establish rates that are fair, just, and reasonable, they have significant discretion in applying this standard. Disallowance of cost recovery could have a negative effect on earnings and cash flows and could result in downgrades of IDACORP’s and Idaho Power’s credit ratings, which could increase the companies’ cost of capital and adversely impact access to the capital markets. Because of the significant impact of ratemaking
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decisions on Idaho Power’s business and financial condition, the company’s management focuses on timely recovery of its costs through filings with the IPUC and the OPUC.
A January 2010 settlement stipulation approved by the IPUC applied a moratorium on general rate relief until January 2012. As a result, Idaho Power’s first opportunity to file a new general rate case with the IPUC is June 2011. As of the date of this report, Idaho Power is evaluating its general rate case needs and options.
Idaho Power has power cost adjustment (PCA) mechanisms that provide for annual adjustments to the rates charged to its Idaho and Oregon retail customers. The PCA tracks Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. Most of the variance between these two amounts is deferred for future recovery from or refund to customers. Because of the PCA mechanism, the primary financial impact of power supply cost variations is on the timing of cash flows. If costs rise above the level currently recovered in retail rates it adversely affects Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. Idaho Power also has a fixed cost adjustment (FCA) mechanism that is designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer.
Idaho Power’s rate structure includes methods such as tiered rates and time-of-use rates. These methods divide a customer’s energy usage into separate tiers and/or time periods based on how many kilowatt-hours of energy a customer uses and the time during which the energy was consumed, and increases the cost of power consumed depending on the applicable tier and time of consumption. Customers are typically required to pay more for energy during periods of high demand and when the amount of usage is large enough to implicate higher rate tiers. These tiers are established by the IPUC and OPUC and are intended to promote energy efficiency and help customers identify opportunities to manage their energy usage and power bill. However, this rate structure can have a significant impact on Idaho Power’s results of operations compared to a flat rate structure, as revenues are more negatively impacted when customers’ usage does not reach the expected rate tier brackets, and more positively impacted when customers use energy in higher-tier pricing brackets and during peak demand times when power rates to customers are higher.
Economic Conditions: Economic conditions within and outside of Idaho Power’s service area can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales due to power demand, and Idaho Power’s need for purchased power. Since 2008, economic conditions in Idaho Power’s service area have been relatively weak. Unemployment rates remain high relative to historic unemployment levels and the customer growth rate has been slow relative to prior years. Management cannot predict when economic recovery may occur in Idaho Power’s service territory. As such, Idaho Power seeks to manage costs while executing on its three part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. In the current economic environment, management continues to focus on factors such as customer growth, customer load, future capital requirements and the timing of capital expenditures, system reliability and efficiency, liquidity and access to capital markets, accounts receivable balances and collections, employee remuneration and retirement benefits plans, and counterparty risk.
Weather Conditions and Associated Impacts: Energy sales to Idaho Power’s customers vary from season to season primarily as a result of weather conditions and agricultural growing conditions. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively. During the growing season, irrigation customers use electricity to operate irrigation pumps. Increased precipitation during the growing season reduces electricity sales to these customers.
The effect of weather on Idaho Power’s hydroelectric power generation projects can also impact Idaho Power’s financial condition and results of operations. Hydroelectric generation depends on stream flows in the Snake River and its tributaries, on which Idaho Power’s hydroelectric facilities are built. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows in the Snake River, spring flows, rainfall, the amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced and reservoir storage is low, Idaho Power’s hydroelectric generation is
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reduced. This results in reduced generation from Idaho Power’s resource portfolio available to serve Idaho Power’s customers and for off-system sales and, generally, an increased use of more expensive coal- or gas-fired generation or purchased power to meet load requirements. Both of these situations result in increased power supply costs. Regional energy market prices can also be affected by hydroelectric generating conditions. In times with high hydroelectric generation, the availability of abundant energy tends to reduce wholesale prices, and during low hydroelectric generation, wholesale prices tend to be higher. While the cost of purchased power is typically higher than the cost of hydroelectric generation, the incremental cost is currently included in the PCA mechanisms that allow Idaho Power to recover most of these costs.
Fuel and Power Supply: In addition to hydroelectric generation, Idaho Power relies primarily on coal and natural gas to fuel its generation facilities. Recently, Idaho Power has experienced an increase in coal prices. Fuel expense at the Jim Bridger plant increased $15 million in 2010 compared to 2009, primarily due to continued production cost increases for coal mined at BCC and higher coal contract prices. In order to help ensure the continued supply of coal for the Jim Bridger plant, BCC received approval in July 2010 from the U.S. Bureau of Land Management (BLM) to modify BCC’s existing federal coal lease to include 560 acres of adjacent coal lands for mine development, and BCC plans to increase lease holdings on bordering private lands for a total increase of approximately 2,000 acres.
Increases in demand for natural gas may result in market price increases, short-term price volatility, and/or supply availability issues. Operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power’s demand for natural gas, and thus its exposure to volatility in natural gas prices.
Idaho Power relies in part on purchased power to meet load requirements; a significant component of Idaho Power’s infrastructure development is intended to ensure transmission capacity is sufficient to meet demand requirements. To help reduce power demand, Idaho Power has several energy efficiency programs in place and in development, targeting savings across the entire year and across a wide range of customer segments. The emphasis of these programs is to reduce energy consumption, especially during periods of high demand, and delay the need to build new supply-side alternatives. The majority of energy efficiency activities are funded through a rider mechanism on customer bills in both Idaho and Oregon and costs related to the program are subject to disallowance if imprudently incurred.
Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel in order to manage the risks relating to fuel and power price exposures. Idaho Power has an energy risk management policy and programs designed to reduce exposure to power supply cost-related uncertainties.
Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits. Compliance with these requirements directly influences Idaho Power’s operating environment and may significantly increase Idaho Power’s operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements these policies and initiatives.
Idaho Power is also subject to a substantial body of rapidly changing regulations by federal, state, and local authorities governing the protection of the environment. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10 percent interest, was recently the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and an anticipated early shut-down of the facility in 2020, and in September 2010 the Environmental Protection Agency (EPA) issued a Notice of Violation to Portland General Electric (PGE), the operator of the Boardman plant, alleging Clean Air Act (CAA) violations. Compliance with environmental laws and regulations will result in increases to capital expenditures and operating expenses. Idaho Power intends to seek recovery of such costs through the ratemaking process.
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Idaho Power is involved in renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and the Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power’s hydroelectric projects. Given the number of parties and issues involved, Idaho Power expects that relicensing costs could be substantial and will be submitted to regulators for recovery through the ratemaking process.
IDACORP and Idaho Power are unable to predict the outcome of these matters or estimate the impact they may have on their consolidated financial position, results of operations, or cash flow.
Other Significant Pending and Completed Matters
Tax-Related Projects: In September 2010, Idaho Power adopted a tax accounting method change for repair-related expenditures on utility assets concurrent with the filing of IDACORP’s 2009 consolidated federal income tax return. Also in 2010, Idaho Power reached an agreement with the Internal Revenue Service (IRS), subject to subsequent review by the U.S. Congress Joint Committee on Taxation, regarding the allocation of mixed service costs in its method of uniform capitalization. The ultimate resolution of these tax matters and the associated regulatory treatment may have a substantial impact on IDACORP’s and Idaho Power’s financial condition and results of operations.
Load-Growth Adjustment Rate Mechanism: In its May 2010 order approving a decrease in the 2010 PCA mechanism and increase in Idaho base rates, the IPUC identified the use of the load growth adjustment rate (LGAR) in times of load decline as an area of contention. On January 14, 2011, Idaho Power submitted comments in support of a revised methodology that was submitted by another utility to the IPUC for consideration. Under the revised methodology, the LGAR would be calculated based on the company’s embedded production revenue requirement that is classified as energy-related or variable for ratemaking purposes. Approval of the new methodology and rate would result in Idaho Power collecting a greater or lesser amount through the PCA mechanism, depending on whether loads during the applicable period increased or decreased.
Retirement Benefit Plans: In September 2010, Idaho Power contributed $60 million to its defined pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in September 2010 for the 2009 plan year. On October 1, 2010, Idaho Power filed an application with the IPUC requesting acceptance of Idaho Power’s 2011 retirement benefit plans. On January 26, 2011, the IPUC issued an order stating that Idaho Power is not precluded from filing for recovery of 2010 contributions before proceedings relating to the October 2010 application are completed. As of the date of this report, a determination and order on the prudency of the 2011 retirement benefits package is pending.
PURPA Contracts: Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory mandated execution of PURPA agreements may result in Idaho Power acquiring energy at above wholesale market prices and at times when a surplus already exists as well as requiring additional operational integration costs, thus increasing costs to Idaho Power’s customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power’s power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates. In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for projects entitled to published avoided cost rates from 10 average MW to 100kW for wind and solar PURPA projects while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher Published Avoided Cost rates, tax incentives, and other benefits.
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Integrated Resource Plan (IRP): Idaho Power’s 2009 IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans. The IPUC accepted for filing the 2009 IRP in August 2010. In October 2010, the OPUC issued an order acknowledging Idaho Power’s 2009 IRP. As of the date of this report, Idaho Power is evaluating its resource portfolio and needs and is working to develop its 2011 IRP.
Water Management Issues: Power generation at the Idaho Power hydroelectric power plants on the Snake River and its tributaries depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River.
Summary of 2010 Financial Results
IDACORP’s net income and earnings per diluted share for the years ended 2010, 2009, and 2008 were as follows:
The following table presents a reconciliation of IDACORP net income for 2009 to 2010 (in millions):
Idaho Power’s 2010 operating income decreased $5.9 million as compared to 2009. Regulatory changes, which include the Idaho rate settlement benefits and the impacts of the PCA and FCA mechanisms, increased operating income by $23.9 million and were partially offset by reductions in sales volumes of $18.4 million. Idaho Power’s operating income also decreased due to a $6.4 million Oregon excess power cost recovery recorded in 2009 that did not recur in 2010.
Sales volumes decreased four percent for the year as compared to 2009 in all customer classes, except irrigation. Mild weather contributed to the reduced electricity demand for customers who rely on electric power for cooling and heating. Other contributing factors included increased energy conservation and continued weak economic conditions evidenced by relatively high unemployment levels and nominal
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customer growth. Relatively low precipitation in Idaho Power’s service territory during the third quarter of 2010 contributed to increased sales to irrigation customers, who rely on electric power to operate irrigation systems. Volume decreases were partially offset by the FCA mechanism and lower power supply costs.
Other items influencing the change in Idaho Power’s 2010 operating income from 2009 included:
transmission revenues, a component of other revenues, increased $4.3 million, resulting primarily from new transmission facilities and increases in the FERC formula rate for transmission services;
depreciation expense increased $5.3 million, due to the acceleration of depreciation expense for non-AMI meters related to Idaho Power’s conversion to Advanced Metering Infrastructure (AMI). Idaho Power has regulatory orders to collect an offsetting amount through rates; and
property tax for Idaho increased $3.0 million, primarily due to lower residential and commercial values in other property classes shifting tax costs to centrally assessed property.
A tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year significantly impacted IDACORP’s and Idaho Power’s 2010 results. In 2010, Idaho Power recorded a tax benefit of $44.5 million related to the cumulative effect of the method change (tax years 1999 through 2009) and included an annual deduction estimate in its 2010 income tax provision, which resulted in an $11.7 million tax benefit. Idaho Power has recorded a current liability for uncertain tax positions of $14.7 million relating to the tax accounting method change for repair-related expenditures.
Also during 2010, Idaho Power recorded a tax method change relating to uniform capitalization with the tax benefits fully offset by a current uncertain tax position liability equal to the 2010 net tax benefit, resulting in no impact on IDACORP's or Idaho Power's net income for 2010. Initially, an uncertain tax position liability of $65.3 million was established for this method change. For the 2010 year, reversing impacts of this temporary difference reduced the uncertain tax position liability by $5.6 million bringing the year-end balance to $59.7 million. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies before concluding that the new method is effectively settled for financial reporting purposes.
Summary of Liquidity and Capital Requirements
IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. In August 2010, Idaho Power issued $200 million of first mortgage bonds. During 2010, IDACORP issued 973,585 shares of its common stock at an average price of $35.47 for aggregate net proceeds of $34 million, pursuant to its continuous equity program. IDACORP contributed $50 million of additional equity to Idaho Power in 2010.
Idaho Power is in a period of significant infrastructure development and has several major projects in development, including the following:
• Langley Gulch Power Plant: Langley Gulch is a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Construction of the plant is underway and is contracted to achieve commercial operation in November 2012. The contract contains incentives intended to advance the in-service date, and Idaho Power estimates that the plant will be in service by June 2012. The total cost estimate for the project including allowance for funds used during construction (AFUDC) is $427 million, $206 million of which Idaho Power has incurred from the inception of the project through December 31, 2010;
• Transmission Projects: Idaho Power is pursuing the development of the Boardman-Hemingway line, a proposed 500-kV line between a station near Boardman, Oregon, and the Hemingway station near Boise, Idaho. Idaho Power estimates total construction costs of $820 million and expects its share of the project to be between 30 and 50 percent. Idaho Power is discussing joint development of the project with other parties. Idaho Power and PacifiCorp are also pursuing the joint development of Gateway West, a project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. The current estimated cost for Idaho Power’s share of the Gateway West project is between $300 million and $500 million;
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• Transmission Equipment Purchase and Sale Arrangements: In May 2010, Idaho Power sold to PacifiCorp a 59.0 percent interest in the 500-kV portions of transmission-related and interconnection equipment located at Idaho Power’s Hemingway station; and PacifiCorp sold to Idaho Power a 20.8 percent interest in the 345-kV portions of transmission-related and interconnection equipment located at PacifiCorp’s Populus station in southeast Idaho; and
• AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): Under the ARRA, in April 2010 Idaho Power finalized the award of a grant of $47 million from the U.S. Department of Energy (DOE). This grant will match a $47 million investment by Idaho Power in smart grid technology, including AMI. Idaho Power has received approximately $18 million from the DOE as of December 31, 2010, and expects to bill and collect monthly over the estimated three-year term of the grant.
In addition to infrastructure development projects, Idaho Power has significant retirement benefit plan funding obligations and capital requirements for relicensing of hydroelectric facilities and planned and anticipated future environmental-related expenditures discussed elsewhere in this MD&A.
Key Operating and Financial Metrics
The 2011 range for capital expenditures includes amounts for the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects, excluding AFUDC.
The estimated hydroelectric generation range is based in part on National Weather Service reports stating that La Nina conditions, including an enhanced chance of above-average precipitation in Idaho and the Snake River Basin, are expected to continue into spring 2011. On February 16, 2011, reservoir storage levels in selected federal reservoirs upstream of Brownlee were approximately 110 percent of average.
RESULTS OF OPERATIONS
This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings over the last three years. In this analysis, the results of 2010 are compared to 2009 and the results of 2009 are compared to 2008.
Results for the Years Ended December 31, 2010, 2009, and
The following table presents earnings (losses) for IDACORP and its subsidiaries:
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Utility Operations
Operating environment: Idaho Power primarily uses its hydroelectric and coal-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Regional energy market purchases and sales are used to balance supply and demand throughout the year. Idaho Power develops operation plans during the year to provide guidance for generation resource utilization and energy market activities. Idaho Power’s energy risk management policy and unit operating requirements provide the framework for the plans. The plans incorporate forecasts for generation unit availability, reservoir storage and stream flows, gas and coal prices, customer loads, and energy market prices.
In developing its plans, Idaho Power determines to what extent its own resources can be used to meet forecast loads and when to transact in the regional energy market. The allocation of hydroelectric generation between heavy load and light load hours or calendar periods is also a consideration. This allocation is intended to utilize the flexibility of the hydroelectric system to shift generation to high value periods, while operating within the constraints imposed on the system, including the integration of intermittent wind generation.
The following table presents Idaho Power’s energy sales and supply (in MWh) for the last three years:
The 0.8 million MWh reduction in hydroelectric generation in 2010 compared to 2009 is primarily due to a decrease in precipitation during the snow accumulation period. Hydroelectric generation in 2010 was 86 percent of the annual median generation of 8.6 million MWh. The observed stream flow data released in August 2010 by the U.S. Corps of Engineers, Northwest Division indicated that Brownlee reservoir inflow for April through July 2010 was 4.6 million acre-feet (maf), compared to 5.6 maf in April through July 2009. Annual Brownlee reservoir inflow for 2010 was 10.7 maf compared to 11.3 maf in 2009 and 10.1 maf in 2008.
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General Business Revenue: The following table presents Idaho Power’s general business revenues, MWh sales, and year-end number of customers for the last three years:
Changes in customer demand and changes in rates are the primary causes of fluctuations in general business revenue. Several significant rate actions have been implemented in the last three years and are discussed further in “Regulatory Matters - Idaho and Oregon Significant Rate Changes” in this MD&A.
The primary influences on customer demand are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps, with increased precipitation reducing electricity usage. The following table presents Boise, Idaho weather conditions for the last three years:
2010 vs. 2009:
Rates: Rate increases positively impacted general business revenue by $16.9 million, due to increases in base retail rates of $73.5 million, partially offset by PCA rate decreases of $56.6 million.
Usage: A decrease in usage reduced general business revenue by $33.4 million. Idaho Power believes the decline in total MWh sales is due primarily to mild temperatures, which decreases power demand for heating and cooling purposes, and partially due to the continued weakness of the economy and energy conservation practices in its service area. A slow economic recovery could result in continued low demand.
Customers: Growth in customer count contributed to a modest increase in general business revenues of $2.9 million. Customer growth from 2009 to 2010 was 0.5 percent.
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2009 vs. 2008:
Rates: Rate changes positively impacted general business revenue by $127.8 million in 2009 as compared to 2008. PCA rate increases accounted for $78.6 million of the increases and base rate changes contributed $49.2 million.
Usage: Reductions in usage decreased general business revenue $37.7 million. Irrigation usage decreased 14 percent primarily due to increased precipitation, which decreases demand for power to operate irrigation pumps. Commercial and industrial usage also declined due to a weaker economy and increased energy efficiency. The LGAR and FCA mechanisms diminished the impact of changes in sales volumes from levels included in base rates.
Customers: Customer growth of one percent increased general business revenues $9.8 million.
Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the last three years:
2010 vs. 2009: Off-system sales revenue decreased $16.2 million in 2010 as compared to 2009. Hydroelectric generation decreased nine percent, which reduced surplus power available for sale. This decrease was partially offset by an 18 percent increase in revenue per MWh due to lower hydro generation in the region which drove wholesale power prices higher.
2009 vs. 2008: Off-system sales revenue declined $27.1 million in 2009 due to lower market prices, partially offset by increased sales. Prices for wholesale power in the Northwest were much lower in 2009 than in 2008 due to an abundance of energy in the region during the spring and fall and due to lower prices for energy commodities such as natural gas. Improved hydroelectric generating conditions and lower system load increased the amount of electricity available for sale.
Other revenues: The following table presents the components of other revenues:
2010 vs. 2009: Other revenues increased $16.7 million, due mainly to the following:
an increase of $4.3 million in transmission revenues. Transmission system revenues increased $2.8 million primarily due to new transmission facilities, as well as rate changes. Wheeling revenue increased $2.1 million primarily due to increases in the FERC formula rate that took effect on October 1, 2009 and October 1, 2010; and
an increase in energy efficiency revenues of $12.4 million, due to increased program activity. Energy efficiency activities are funded through rider mechanisms on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.
2009 vs. 2008: Other revenues increased $17.5 million, due mainly to the following:
an increase of $4.6 million in transmission revenues, due primarily to transmission rate refunds ordered by the FERC reducing 2008 revenues. Idaho Power recorded in 2008 approximately $4 million of refunds related to transmission sales from prior years; and
an increase of $12.9 million in energy efficiency revenues. These revenues mirror program expenditures and result in a zero net impact on net income. Energy efficiency revenues and expenses have steadily increased as program activity has increased.
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Purchased power: The following table presents Idaho Power’s purchased power expenses and volumes:
2010 vs. 2009: Purchased power expense decreased $23.4 million in 2010 compared to 2009, due to lower system loads that resulted from mild weather, relatively weak economic conditions, energy conservation practices, and a greater reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions.
2009 vs. 2008: Purchased power expense decreased $71.2 million due to lower system load and more favorable hydroelectric generating conditions, which decreased the amount of purchased power Idaho Power needed to serve loads.
The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase power during heavy load periods, which is higher priced energy, than during light load periods, which is lower priced energy, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Also, in accordance with Idaho Power’s risk management policy, Idaho Power may purchase or sell energy several months in advance of delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transactions prices.
Fuel expense: The following table presents Idaho Power’s fuel expenses and generation at its coal and natural gas generating plants:
2010 vs. 2009: Fuel expense increased $10.1 million, due to new contracts with Black Butte Coal Company for the Valmy and Jim Bridger plants that reflect price increases related to diesel fuel and materials and supplies at the Black Butte mine. BCC, which also supplies coal to the Jim Bridger plant, experienced higher labor-related costs due to a tight labor market in the southwest Wyoming area and higher materials and supplies expense related to the underground mining operation. In 2011, there are no significant contract expirations and prices are expected to be similar to 2010; however, most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. Fuel expense also increased due to a 31 percent increase in generation at the Boardman plant due to an extended outage in 2009 that did not recur in 2010, increasing fuel expense $1.8 million. These increases were partially offset by a $6.6 million decrease in fuel expense at the natural gas-fired peaking plants.
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2009 vs. 2008: Fuel expense remained nearly the same due to offsetting variances. The decrease in generation is due to lower system loads and lower wholesale energy prices, which resulted in reduced dispatch due to economics, and an unplanned mid-year maintenance outage at Boardman. Coal prices were higher in 2009 due to an increase in operating costs at BCC, which supplies coal to the Jim Bridger plant, as well as higher prices for coal delivered to the Boardman plant.
PCA: PCA expense represents the effects of the Idaho and Oregon power supply costs deferral mechanisms, which are discussed in more detail below in “Regulatory Matters - Idaho and Oregon Deferred Net Power Supply Costs” in this MD&A and in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report. In each year presented, net power supply costs were higher than the amounts estimated in the annual PCA forecast, resulting in the deferral of costs for recovery in subsequent rate years. As the deferred costs are recovered in rates, the deferred balances are amortized. The following table presents the components of the PCA:
2010 vs. 2009: A combination of changes in base power supply costs, elements of the PCA mechanism, and a decrease in PCA rates reduced PCA expenses $15.5 million compared to 2009. The $49.9 million decrease in the amortization of the prior year’s deferral balance resulted from lower PCA true-up rates in effect in 2010. The $28.2 million decrease in the Idaho deferral is due to changes in base and actual power supply costs and forecast rates. In addition, in the second quarter of 2009 Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.
2009 vs. 2008: The $114.1 million change in the PCA is due primarily to lower deferral of power supply costs and higher amortization of previously deferred power supply costs.
Other operations and maintenance (O&M) expenses:
2010 vs. 2009: Other O&M expense increased $1.3 million, an increase of less than one percent.
2009 vs. 2008: Other O&M expenses increased $6.3 million, due primarily to an $8.1 million increase in labor related charges and a $1.6 million increase in charges for uncollectible accounts, partially offset by decreases of $4.0 million in legal, other contracted services, and office supplies due to cost containment measures.
Energy efficiency: The majority of energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. Energy efficiency expenses were $44.2 million, $31.8 million, and $18.9 million in 2010, 2009, and 2008, respectively. The remaining $1.4 million of energy efficiency expenses for 2010 are in Other O&M and recovered through base rates.
The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. An asset balance indicates that Idaho Power has spent more than it has collected and a liability balance indicates that Idaho Power has collected more than it has spent. At December 31, 2010, Idaho Power’s rider balance was a regulatory asset of $19.5 million.
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Non-utility Operations
IFS: IFS had an immaterial impact on net income in 2010. IFS contributed $1 million and $3 million to net income in 2009 and 2008, respectively, principally from the generation of federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and other real estate investments.
IFS made $6.7 million in new investments in 2010 and invested $14 million, and $8 million in new investments in 2009 and 2008, respectively. IFS generated tax credits of $7 million, $8 million, and $11 million during 2010, 2009, and 2008, respectively.
Ida-West: Ida-West had net income of $3 million, $3 million, and $2 million in 2010, 2009, and 2008, respectively. Ida-West continues to hold joint venture investments in independent power projects.
Income Taxes
IDACORP’s and Idaho Power’s income tax expense for the year ended December 31, 2010 decreased substantially relative to 2009 and 2008, primarily as a result of Idaho Power’s tax accounting method change for repair-related expenditures and lower pre-tax earnings at IDACORP and Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for 2010 were comparable to 2009. For additional information relating to IDACORP’s and Idaho Power’s income taxes, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report, and the discussion below.
Tax Accounting Method Change for Repair-Related Expenditures: In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return.
For the year ended December 31, 2010, Idaho Power recorded a $44.5 million tax benefit related to the filed deduction for the cumulative method change adjustment and an additional $11.7 million tax benefit for the annual deduction estimate included in its 2010 income tax provision. As of December 31, 2010, Idaho Power had a current uncertain tax position liability of $14.7 million related to this method. The estimated annual tax deduction related to capitalized repairs produces a net tax benefit of $9 million annually, which is approximately $5 million higher than Idaho Power’s prior repair deduction method reported in 2009. In addition, the reversal of this temporary difference will offset a portion of the ongoing annual benefit.
Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse.
As of the date of this report, the tax method is being audited under IDACORP’s 2009 Compliance Assurance Process (CAP) examination (discussed below) and, on a national level, aspects of the method related to electric utility generation, transmission, and distribution property are the subject of an IRS Industry Issue Resolution program. IDACORP and Idaho Power cannot predict exactly when the audit of the method will conclude or when national guidance related to utility property will be issued, but believe it is reasonably possible during fiscal year 2011.
Status of Audit Proceedings and Uniform Capitalization Method Change: In May 2009, IDACORP formally entered the IRS CAP program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. In January 2010, IDACORP was accepted into the CAP program for its 2010 tax year. With the exception of Idaho Power’s capitalized repairs method (discussed above) and uniform capitalization method (discussed below), IDACORP and Idaho Power believe there are no remaining tax uncertainties for the 2009 tax year and expect that the 2009 examination may conclude during fiscal year 2011. IDACORP and Idaho Power are unable to predict the outcome of the 2010 examination.
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Specifically within the 2009 CAP examination, the IRS audited Idaho Power’s method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return. Due to the method change agreement with the IRS, Idaho Power reversed the uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for the year ended December 31, 2010.
The resulting tax deductions available under the agreed upon uniform capitalization method are significantly greater than Idaho Power’s prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of current year tax expense from the reversal of this temporary difference. The prescribed regulatory accounting treatment for this method is the same as discussed earlier for the capitalized repairs method.
As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal to the $59.7 million net tax benefit recorded for the method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes. IDACORP and Idaho Power cannot predict exactly when Joint Committee review will occur, but believe it is reasonably possible during fiscal year 2011. The estimated annual tax deduction related to the uniform capitalization method, if approved, will produce a tax benefit that approximates the annual net tax benefit reported for the capitalized repairs method.
Cash Impacts of Tax Method Changes: IDACORP and Idaho Power have realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. The majority of this cash benefit has been realized through reductions to cash payments that would have otherwise been owed to taxing authorities for the 2009 tax year and a federal refund of $24 million received in the fourth quarter of 2010. Additionally, approximately $6 million of state cash benefits were realized through reduced tax payments for the 2010 year.
The capitalized repairs and uniform capitalization method changes produced an income statement tax benefit of $44.5 million and $65.3 million, respectively, prior to the accrual for uncertain tax positions. A portion of this earnings benefit relates to previously deferred income tax expense being flowed through the income statement which does not deliver any cash benefits. In addition, federal tax credits of $17 million previously recognized were restored due to the reduction of 2009 taxable income by the two method changes. The restored credits were a reduction to cash received in 2010, but will be available to deliver cash benefits in future periods.
New Tax Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) were both enacted in 2010. While the legislation contained many income tax related provisions for individuals and businesses, one item of significance for capital intensive industries was the extension and increase of bonus depreciation. Bonus depreciation provides for the accelerated deduction of current capital expenditures. The Jobs Act extended 50 percent bonus depreciation to 2010 and the Tax Relief Act extended bonus depreciation to 2011-2012 and increased it to 100 percent for a portion of 2010 and 2011. Additional technical guidance from the Treasury Department on the application of bonus depreciation to self-constructed assets is expected in the first half of 2011, as well as decisions by various states on conformity with the federal law. IDACORP and Idaho Power are currently evaluating the potential impact that the federal extension of bonus depreciation could have on its 2011 and 2012 taxable income, operating results, cash flows, capital expenditure plans, and regulatory objectives.
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LIQUIDITY AND CAPITAL RESOURCES
Overview
IDACORP’s operating cash flows are driven principally by Idaho Power, and the primary source of operating cash flows for Idaho Power is sales of electricity and transmission capacity. General business revenues and the costs to supply power to general business customers, and the timing of income tax payments, are factors that have the greatest impact on Idaho Power’s operating cash flows and are subject to risks and uncertainties relating to power generation conditions and Idaho Power’s ability to obtain rate relief to cover its operating costs and provide a return on investment.
Significant uses of cash flows from Idaho Power’s utility operations include the purchase of electricity, the purchase of fuel for power generation, and payment of other operating expenses, taxes, and interest, with any excess amount being available for other uses such as capital expenditures and the payment of dividends. Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power’s aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to heavy infrastructure requirements in the near term, Idaho Power has recently focused on critical infrastructure needs that relate to system reliability and resource adequacy, and expects that total capital expenditures will be between $775 million and $805 million from 2011 through 2013. See “Capital Requirements” below for a further discussion of Idaho Power’s current and anticipated infrastructure development requirements and associated capital expenditure estimates. Idaho Power also made a $60 million cash contribution to its defined benefit pension plan in September 2010 and expects significant future cash contribution obligations under that plan.
Idaho Power’s operating cash flows usually do not fully support the amount required for utility capital expenditures, particularly during a period of heavy infrastructure development as is presently occurring. Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from continuing operations, public debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates, periodically filing for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power’s earned returns with those allowed by regulators.
IDACORP’s and Idaho Power’s access to long-term and short-term debt markets, including their respective $100 million and $300 million credit facilities, helps provide necessary liquidity to support operating activities. In addition to access to its credit facility, as of the date of this report IDACORP has approximately $539 million remaining on a shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP has a sales agency agreement that expires in November 2011 with BNY Mellon Capital Markets, LLC where approximately 1.2 million shares of common stock remain available to be sold from time to time in at-the-market offerings. As of the date of this report, Idaho Power has $300 million remaining on a shelf registration statement that can be used for the issuance of first mortgage bonds and debt securities. In 2010, Idaho Power issued $200 million of first mortgage bonds, of which a significant portion of the net proceeds are intended to fund upcoming debt maturities.
IDACORP and Idaho Power also meet short-term liquidity requirements through the issuance of commercial paper, which under recent commercial paper market conditions has been a relatively low-cost, flexible borrowing option. While short-term borrowing costs have not been significant recently, any future uncertainty in the credit markets may result in increased costs for commercial paper borrowings or limit the ability to issue commercial paper, which may increase IDACORP’s and Idaho Power’s reliance on their respective credit facilities for short-term liquidity purposes.
The conditions of the capital markets in recent periods and the weak economy have caused a general concern regarding access to sufficient capital at a reasonable cost. IDACORP and Idaho Power have not been significantly impacted by the recent disruption in the credit environment and currently expect to continue to be able to access the capital markets to meet short- and long-term borrowing needs.
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Operating Cash Flows
IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2010, were $305 million and $330 million, respectively. These amounts were an increase of $21 million and $58 million, respectively, compared to the year ended December 31, 2009. The following are significant items that affected operating cash flows in 2010:
• IDACORP’s net refunds for income taxes were $27 million in 2010, as compared with $21 million in 2009. Idaho Power’s net refunds from IDACORP for income tax were $57 million in 2010, as compared with $14 million in 2009;
• changes in accounts payable balances increased operating cash flows $32 million. Idaho Power paid less during 2010 for prior-year operating expense than it did in 2009 and carried over more current-year expense to be paid in 2011 than it did in 2009. Changes in amounts owed for purchased power and for coal contributed $14 million and $8 million, respectively, to the change;
• changes in retail customer accounts receivable and unbilled revenue balances increased cash flows as a colder than normal December in 2009 caused these balances to be significantly higher at the end of that year than in either 2008 or 2010. The 2009 increase in accounts receivable and unbilled revenue balances of $19 million reflects a timing difference that results in Idaho Power collecting less from customers during the year than it recorded as revenue. The subsequent decrease in those balances during 2010 of $13 million reflects the reversal of that timing difference and results in collections exceeding accrued revenues. This change in out-of-period collections from 2009 to 2010 increased cash flows by $32 million as compared with 2009;
• in the first quarter of 2009, $13 million of refunds were made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s OATT; and
• a $60 million contribution was made to the defined benefit pension plan, decreasing operating cash flows in September 2010. No contribution was made in 2009.
IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2009 were $284 million and $272 million, respectively. These amounts were an increase of $148 million and $153 million, respectively, compared to the year ended December 31, 2008. The following are significant items that affected operating cash flows in 2009:
• in 2009, PCA rates more closely matched actual net power supply costs than in 2008. This more timely recovery of current costs improved cash flows by approximately $65 million compared to 2008. In addition, the collection of deferred net power supply costs increased $49 million compared to 2008;
• changes in net cash paid and refunded for income taxes improved cash flows by $42 million and $50 million at IDACORP and Idaho Power, respectively, primarily due to audit settlements;
• a refund of $13 million was made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s OATT; and
• net income increased by approximately $26 million and $28 million at IDACORP and Idaho Power, respectively, compared to 2008.
Pension Funding: In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan. The contribution was $54 million in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan year. The higher contribution amount was made for reasons that include bringing the pension plan to a more funded position, reducing future required contributions, and reducing Pension Benefit Guaranty Corporation premiums. Idaho Power expects to make additional significant cash contributions to its pension plan and has significant funding obligations under postretirement benefit plans at least through 2015.
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and the estimated liabilities of the plans. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. The funded status may change over time due to several factors, including contribution levels, assumed discount rates, and actual and assumed rates of return on plan assets.
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IDACORP and Idaho Power continuously monitor available and proposed pension funding guidance and financial market conditions and their impact on the pension plan, and evaluate the potential impact on funding requirements and strategies.
In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act (Pension Relief Act) was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011. If an alternate funding option is elected, it would reduce near-term required contributions to the plan by spreading them over a longer time period. Idaho Power has determined not to make the election permitted by the Pension Relief Act for the 2008-2010 plan years, but continues to evaluate the legislation’s potential impact on the 2011 plan year. Unless IDACORP and Idaho Power elect an alternative amortization schedule under the new legislation for 2011, minimum required contributions to the defined benefit pension plan are estimated to be approximately $3 million in 2011, $46 million in 2012, $36 million in 2013, $32 million in 2014, and $31 million in 2015. IDACORP and Idaho Power may elect to make contributions earlier than and larger than required. See Note 11 - “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to the Pension Relief Act and Idaho Power’s pension plan funding and postretirement benefit obligations, and Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.
Investing Cash Flows
Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s distribution, transmission, and generation facilities. These capital expenditures are for the construction of infrastructure needed to address customer growth, peak demand growth, and aging plant and equipment. Idaho Power’s construction expenditures were $338 million, $252 million, and $244 million in 2010, 2009 and 2008, respectively. In 2010, construction expenditures were partially offset by proceeds from the sale of $19 million of transmission-related assets to PacifiCorp.
In May 2008, IDACORP and Idaho Power withdrew $20 million from a refundable tax deposit previously made with the IRS. In December 2008 the remainder of the deposit, approximately $25 million, was applied to accrued taxes and interest.
IDACORP cash flows relating to investments in affordable housing through IFS were $13 million, $6 million, and $8 million in 2010, 2009, and 2008, respectively.
Financing Cash Flows
Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and credit facilities. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.
Debt: On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under its shelf registration statement. Idaho Power expects to use a portion of the proceeds from this issuance to repay $120 million of first mortgage bonds that mature in the first quarter of 2011.
On December 1, 2009, Idaho Power repaid $80 million of its 7.2% First Mortgage Bonds. On November 20, 2009, Idaho Power issued $130 million of its 4.5% First Mortgage Bonds, Secured Medium Term Notes, Series H, due March 1, 2020. On August 20, 2009, Idaho Power completed the remarketing of its $166.1 million Pollution Control Revenue Refunding Bonds and on August 25, 2009, Idaho Power used the proceeds from the remarketed bonds plus other funds to prepay its $170 million Term Loan Credit
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Agreement. On March 30, 2009, Idaho Power issued $100 million of its 6.15% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due April 1, 2019. During 2009, IDACORP and Idaho Power reduced short-term debt by $94 million and $109 million, respectively.
On July 10, 2008, Idaho Power issued $120 million of its 6.025% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due July 15, 2018. These issuances were used to retire short-term and long-term debt and finance capital expenditures.
Equity: IDACORP has entered into sales agency agreements as a means of selling its common stock from time to time in at-the-market offerings. Under these agreements IDACORP received $34 million, net of agent’s fees, in 2010 from the issuance of 973,585 shares at an average price of $35.47. In 2009, IDACORP received $14 million, net of agent’s fees, from the issuance of 489,360 shares at an average price of $28.79. In 2008, IDACORP received $41 million from the issuance of 1,453,967 shares an average price of $28.72. IDACORP’s current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2010, there were 1.2 million shares remaining on the current sales agency agreement.
IDACORP uses original issue common stock for its Dividend Reinvestment and Stock Purchase Plan and 401(k) plan for the purpose of adding additional common equity to its capital structure. Under these plans, IDACORP issued 250,030 shares in 2010, 366,673 shares in 2009, and 280,250 shares in 2008, for proceeds of $8.6 million, $9.6 million, and $8.4 million, respectively.
IDACORP issued 194,860 shares in 2010, 25,800 shares in 2009, and 30,700 shares in 2008, in connection with the exercise of stock options, for proceeds of $5.4 million, $0.6 million, and $0.9 million, respectively.
IDACORP and Idaho Power paid dividends of $58 million, $57 million, and $54 million in 2010, 2009, and 2008, respectively. IDACORP made capital contributions of $50 million, $20 million, and $37 million to Idaho Power in 2010, 2009, and 2008, respectively.
Financing Programs
IDACORP’s consolidated capital structure consisted of common equity of 48 percent and debt of 52 percent at December 31, 2010. Idaho Power’s consolidated capital structure consisted of common equity of 47 percent and debt of 53 percent at December 31, 2010.
Shelf Registrations: IDACORP has an effective registration statement that as of the date of this report can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective registration statement that as of the date of this report can be used for the issuance of up to $300 million of first mortgage bonds and unsecured debt. Refer to Note 4 - “Long-Term Debt” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report for more information regarding long-term financing arrangements.
Credit Facilities: IDACORP and Idaho Power each have a five-year credit agreement that terminates on April 25, 2012, to be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. IDACORP’s facility permits borrowings of up to $100 million at any one time outstanding, which may be increased upon request to $150 million. Idaho Power’s facility permits borrowings of up to $300 million at any one time outstanding, which may be increased upon request to $450 million. Each company may request one-year extensions of the then existing termination date. Interest on borrowings under the facilities is a Eurodollar rate or a floating rate, plus a margin determined by the company’s ratings on its senior unsecured long-term debt securities. The companies also pay a utilization fee and a facility fee.
Each facility contains a covenant requiring a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, excluding indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders’ equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2010, the leverage ratios for IDACORP and Idaho Power
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were 52 percent and 53 percent, respectively. IDACORP’s and Idaho Power’s ability to utilize the credit facilities is subject to continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit or restrict certain investments or acquisitions, mergers or sale or disposition of property without consent, the creation of certain liens, and any agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.
The events of default under the facilities include nonpayment of principal, interest, and fees, when due or subject to a grace period; materially false representations or warranties; breach of covenants, subject in some instances to grace periods; bankruptcy or insolvency-related events; default in the payment of indebtedness in excess of $25 million, defaults that will permit acceleration of such debt, or the acceleration of any of such debt; the acquisition of 20 percent of the outstanding voting shares of the company; the failure of IDACORP to own all of the outstanding voting stock of Idaho Power; any reportable event occurring with any employee pension benefit plan as defined by the Internal Revenue Code or the Employee Retirement Income Security Act of 1974 (ERISA); failure to meet minimum funding standards for any employee pension benefit plan under the Internal Revenue code or ERISA; notice provided by Idaho Power to terminate an employee pension benefit plan if the plan’s unfunded liabilities exceed $75 million; and environmental proceedings, investigations, or violations of law which could reasonably be expected to have a material adverse effect.
A default or an acceleration of indebtedness of IDACORP or Idaho Power in excess of $25 million, including indebtedness under the applicable facility, will result in a cross default under the other facility. Upon any bankruptcy or insolvency-related event of default, the obligations of the lenders to make loans under the facility will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding more than 50 percent of the outstanding loans or of the aggregate commitments may terminate or suspend the obligations to make loans or declare the obligations to be due and payable.
A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power’s ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders. The IPUC order provides that Idaho Power’s authority will continue for 364 days from such downgrade, if Idaho Power promptly notifies the IPUC and files to continue its original authority to borrow. The Oregon statutes permit the issuance of short-term debt without approval of the OPUC.
Without additional approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.
The following table outlines available liquidity as of December 31, 2010 and 2009:
At February 18, 2011, IDACORP had no loans under its credit facility and $75 million of commercial paper outstanding and Idaho Power had no loans under its credit facility and no commercial paper outstanding.
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The following table presents additional information about short-term borrowing during 2010:
Impact of Credit Ratings on Liquidity
IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets may depend on the credit ratings of the entity that is accessing the capital markets. As discussed above, IDACORP’s and Idaho Power’s credit facilities are also affected by the companies’ credit ratings.
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 agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.
Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2010, Idaho Power had posted approximately $4.6 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to forward contracts and derivative instruments could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, 2010, the amount of additional collateral that could be requested upon a downgrade to below investment grade as of that date was approximately $17 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.
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Capital Requirements
Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power’s aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to the heavy infrastructure requirements from 2011-2013, Idaho Power will continue to focus on critical infrastructure needs that relate to system reliability and resource adequacy and has reduced ongoing capital expenditures and major projects from prior estimates. The table below presents the low and high ranges of estimates of the capital expenditure categories. Idaho Power expects that total capital expenditures will be between $775 million and $805 million from 2011-2013. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2011 through 2013. While circumstances could change, IDACORP and Idaho Power expect minimal need for external financing in 2011, other than issuances under the dividend reinvestment and employee-related plans and potentially issuances of IDACORP common stock pursuant to its continuous equity program. Beyond 2011, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. As discussed above, for future external financing needs IDACORP and Idaho Power have shelf registration statements available for the issuance of equity (in the case of IDACORP only) and debt securities, as well as credit facilities.
The following table presents Idaho Power’s estimated cash requirements for construction, excluding AFUDC, for 2011 through 2013 (in millions of dollars):
Langley Gulch Power Plant: The Langley Gulch Power Plant is a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. Construction of the plant, substation, and one of the two required transmission lines is underway. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012. The total cost estimate for the project including AFUDC is $427 million, $206 million of which Idaho Power has incurred from inception in 2009 through December 31, 2010. During 2010, Idaho Power received an air quality permit to construct and commenced construction. Construction activities have included earthwork, underground electrical duct bank and piping, foundations, structures, and equipment erection. The combustion turbine and generator were delivered to the site in December 2010. A contract has been issued for the water delivery system and construction has begun. Contracts have been issued for the gas delivery system, and it is currently under design. The plant will connect to Idaho Power’s existing grid through a new substation and two new transmission lines. As of December 31, 2010, construction of the substation and one of the transmission lines is approximately 50 percent complete. The second transmission line is not expected to be complete until May 2012.
Other Major Projects:
Hemingway Station: Idaho Power recently completed construction of the 500-kV Hemingway station, located near Boise, Idaho. This station was constructed to relieve capacity and operating constraints to enhance reliable service to Idaho Power’s network and native load customers and was placed in service in July 2010 at a total cost of approximately $58 million. PacifiCorp acquired an ownership interest in the Hemingway station as discussed below in “Memorandum of Understanding and Related Transactions with PacifiCorp.”
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Hemingway-Bowmont Transmission Line: The Hemingway-Bowmont transmission line consists of 13 miles of new 230-kV transmission line that provides power to the Treasure Valley in southwest Idaho. The project was placed in service in 2010 at a total cost of approximately $15 million.
Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 299 mile, 500-kV transmission project between a substation near Boardman, Oregon and the Hemingway station. This line will provide transmission service to meet needs identified in the 2009 IRP and other requests pursuant to Idaho Power’s OATT. The Oregon Energy Facility Siting Council (EFSC) process and the National Environmental Policy Act (NEPA) process are under way. Idaho Power is working with the EFSC to develop a phased approach to their process so it can run concurrently with the NEPA process. The U.S. Bureau of Land Management (BLM) is expected to determine in the first quarter of 2011which additional routes identified in scoping will be analyzed in the NEPA process along with Idaho Power’s proposed and alternate routes. The Oregon Department of Fish and Wildlife (ODFW) is working with Idaho Power to minimize the impact of the conservation plan for the greater sage grouse on the proposed route. The cost of the initial phase of the project, consisting of engineering, environmental review, permitting, and acquisition of rights-of-way, is estimated at $92 million, including AFUDC, $13 million of which Idaho Power has incurred through December 31, 2010. Total cost estimates for the project are approximately $820 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power expects its share of the project to be between 30 and 50 percent. The 2011 to 2013 cost estimate, excluding AFUDC and assuming Idaho Power’s share of the project is approximately 30 percent, is included in the Capital Requirements table above. Construction costs beyond the initial phase are not included in the table above. While Idaho Power’s forecast of load requirements indicates that immediate system reliability benefits could be realized by accelerating construction of the transmission line for an earlier in-service date, Idaho Power is currently targeting a completion date of mid-2016 for the project, subject to siting, permitting, regulatory approvals, and other conditions. Idaho Power expects to receive a draft environmental impact statement (EIS) from the BLM relating to the project in early 2012. Idaho Power will continue to work with ODFW and other agencies to address environmental issues, including proposed lawmaking relating to sage grouse in Oregon, which could delay the project, alter the proposed siting, and result in significantly higher costs.
Gateway West Project: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. Idaho Power and PacifiCorp have a cost sharing agreement for expenses incurred for analysis work of the initial phases. Idaho Power’s share of the initial phase, consisting of engineering, environmental review, permitting, and acquisition of rights-of-way, is approximately $40 million, including AFUDC, $14 million of which Idaho Power had incurred through December 31, 2010. Initial phases of the project could be completed by 2014; however, timing of the project’s segments may be deferred and constructed as demand requires. Idaho Power’s share will vary by segment across the project and the current estimated total cost for its share is between $300 million and $500 million, including AFUDC. Only initial phase cost estimates for the 2011 to 2013 timeframe, excluding AFUDC, are included in the Capital Requirements table above. Idaho Power anticipates receiving a draft EIS from the BLM in 2011.
AMI/Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of December 31, 2010, Idaho Power had installed approximately 343,000 AMI meters at a cost of $49 million. On May 28, 2010, the IPUC approved Idaho Power’s request to include the 2010 AMI investment in its rate base. The requested increase to rates of approximately $2.4 million was effective June 1, 2010. The total cost estimates for the project are approximately $74 million. The 2011 estimated costs are included in the Capital Requirements table above.
Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010. Idaho Power received approximately $18 million from the DOE as of December 31, 2010, and expects to bill and collect monthly over the term of the three-year contract. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.
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Memorandum of Understanding and Related Transactions with PacifiCorp:
Memorandum of Understanding: Idaho Power is committed to the development of transmission facilities to fulfill its service obligations and to operate reliable transmission systems. On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects. The parties also agreed to negotiate in good faith to reach arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of parts of the systems; cost-sharing; capital improvements; and each party’s rights to a specified transmission capacity on applicable transmission lines. The MOU further provides that Idaho Power and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate existing transmission capacity rights agreements over portions of Idaho Power’s existing transmission system and replace them with new agreements, if required. On July 29, 2010, Idaho Power and PacifiCorp mutually agreed to extend the final date to execute and deliver definitive agreements under the MOU from September 1, 2010 to November 5, 2010. On November 4, 2010, the parties agreed to further extend the timeframe to complete the negotiations to December 31, 2011. The MOU may be terminated by either party at any time.
Joint Purchase and Sale Agreement and Joint Operating Agreements: In connection with the MOU, on April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which Idaho Power agreed to sell to PacifiCorp a 59.0 percent interest in certain high-voltage transmission-related and interconnection equipment located at the Hemingway station south of Boise, Idaho, and PacifiCorp agreed to sell to Idaho Power a 20.8 percent interest in certain high-voltage transmission-related and interconnection equipment located at PacifiCorp’s Populus station in southeast Idaho. Closing of the purchase and sale occurred on May 3, 2010. Construction of the Hemingway and Populus stations is substantially complete. Upon final completion, the estimated purchase price PacifiCorp will have paid to Idaho Power for PacifiCorp’s interest in the Hemingway station is $13.4 million, and the estimated purchase price Idaho Power will have paid to PacifiCorp for Idaho Power’s interest in the Populus station is $14.3 million.
The Hemingway and Populus stations are owned and operated in accordance with separate Joint Ownership and Operating Agreements (Operating Agreements), each dated May 3, 2010. The Operating Agreements include terms relating to the obligations of Idaho Power and PacifiCorp as the operators of the Hemingway and Populus stations, respectively, including, among other items, construction of additional transmission and interconnection equipment at the stations, cost sharing, operation and maintenance, and interconnection and energizing of the transmission systems. On May 10, 2010, Idaho Power and PacifiCorp filed the Operating Agreements with the FERC, requesting that the FERC determine that the rates that Idaho Power and PacifiCorp were imposing on one another pursuant to the Operating Agreements were just and reasonable. On July 9, 2010, following the filing of an intervention and protest by the Bonneville Power Administration, the FERC issued an order finding that the terms, conditions, and rates in the Operating Agreements were just and reasonable, and accepted the Operating Agreements for filing effective July 10, 2010.
Environmental Regulation Costs:
Idaho Power anticipates approximately $42 million in annual capital and operating costs for environmental facilities during 2011. Hydroelectric facility expenses, including costs for relicensing the HCC, and thermal plant expenses account for approximately $25 million and $17 million, respectively. From 2012 through 2013, total environmental-related operating and capital costs are estimated to be approximately $151 million. Expenses related to the hydroelectric facilities during that period are expected to be $84 million and include costs associated with the relicensing of the HCC. Thermal plant expenses are expected to total $67 million during this period. The capital portion of these amounts are included in the Capital Requirements table above but do not include costs related to possible changes in environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.
Other Capital Requirements: IDACORP’s non-regulated capital expenditures have primarily related to IFS’s tax-structured investments. Currently there are no significant expenditures anticipated for 2011 through 2013.
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Retirement Benefit Plans
Idaho Power has significant future contribution obligations under its retirement benefit plans. Refer to Note 11 - “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.
Off-Balance Sheet Arrangements
Idaho Power has agreed to guarantee the performance of reclamation activities at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At this time BCC is revising its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per ton surcharge if it is determined that future liabilities exceed the trust’s assets. Because of the existence of the fund and the ability to apply a per ton surcharge, the estimated fair value of this guarantee is not material.
Contractual Obligations
The following table presents IDACORP’s and Idaho Power’s contractual cash obligations for the respective periods in which they are due:
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REGULATORY MATTERS:
Overview
As a regulated utility, Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Idaho Power uses general rate cases, PCA mechanisms, an FCA mechanism, and subject-specific filings to recover its costs of providing service and to potentially earn a return on investment.
Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC. Discussed below are filings and important regulatory determinations that have been recently made. Regulatory matters and the financial impact of rate decisions are also discussed in “Results of Operations” of this MD&A and in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
Idaho and Oregon Significant Rate Changes
As a regulated utility, the price that the IPUC and OPUC authorize Idaho Power to charge for its retail services is a major factor in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The table below summarizes notable rate increases and decreases, shown on an annualized basis. Certain of the regulatory actions that resulted in the rate increases and decreases are described in more detail in this section of MD&A.
Idaho and Oregon Deferred Net Power Supply Costs
As discussed above, Idaho Power’s power supply costs can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets. To address the volatility of power supply costs, Idaho Power has power cost adjustment, or PCA, mechanisms in both Idaho and Oregon. These mechanisms allow Idaho Power to recover from or refund to customers a majority of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, resulting in fluctuations in operating cash flows from year to year.
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For a summary of the changes in deferred power supply costs for the years ended 2009 and 2010, as well as a more detailed description of the PCA mechanisms, refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
A net decrease of $64.5 million in Idaho Power’s balance of deferred power supply costs from January 1, 2009 to December 31, 2009, and a net decrease of $54.9 million in Idaho Power’s balance of deferred power supply costs from January 1, 2010 to December 31, 2010, was a result of the collection of previously deferred costs through PCA rates.
Significant Idaho Regulatory Matters
Idaho Settlement Agreement and Related Impacts: On January 13, 2010, the IPUC approved a rate settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and other parties. The settlement agreement contains four important elements: (1) a general rate freeze until January 1, 2012, with some exceptions; (2) a specified distribution of the expected 2010 PCA decrease to directly reduce customer rates, providing some general rate relief to Idaho Power and resetting base level power supply costs for the PCA going forward; (3) use of investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction; and (4) an equal sharing of any Idaho earnings exceeding the authorized return on year-end equity of 10.5 percent. Further details on the terms of the settlement agreement are set forth in Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
The settlement agreement provided for additional amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power’s actual return on year-end equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Because Idaho Power’s 2009 and 2010 Idaho-jurisdiction returns on year-end equity were between 9.5 and 10.5 percent, the sharing and additional ADITC amortization provisions of the settlement were not triggered. Idaho Power has available $25 million of additional ADITC amortization for use in 2011, in accordance with the settlement.
On January 19, 2010, Idaho Power filed with the IPUC a request to reestablish base net power supply costs with an increase of $74.8 million in the Idaho jurisdiction. On April 13, 2010, the IPUC found that adjustments for PURPA contracts ($7.1 million) and the Hoku contract ($4.0 million) as proposed by the IPUC Staff were reasonable reductions to Idaho Power’s proposed base net power supply expenses. The remaining amount of $63.7 million was approved as a working number for Idaho Power’s 2010 PCA filing, and later adopted by the IPUC as part of the 2010 PCA case, described below.
2010 PCA Filing and Order; LGAR Mechanism: On April 15, 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010 through May 31, 2011, and to change base rates, pursuant to the terms of the January 2010 Idaho settlement agreement. The January 2010 settlement agreement provides that PCA rates will be reduced by the full calculated amount and that base rates will be increased in an amount that partially offsets the PCA decrease. On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The net effect of these two rate adjustments was an overall decrease in Idaho jurisdiction customer rates of $58.2 million, or 6.49 percent, effective June 1, 2010. The $88.7 million base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in base rates.
The IPUC’s May 2010 order identified the use of the LGAR in times of load decline as an item of contention raised by intervening parties. The LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The LGAR recognizes that the power supply expenses recovered through Idaho Power’s base rates changes as loads increase or decrease. The LGAR adjusts, upwards or downwards, power supply costs Idaho Power recovers through its PCA for differences between actual load and the load used in calculating base rates. Idaho Power’s true-up calculation for the PCA included an increase of $21.3 million for the decline in load growth for the Idaho jurisdiction. The IPUC’s order, which made no changes to the LGAR, stated that it expects the IPUC Staff, Idaho Power, and interested parties to meet to address an appropriate change to the LGAR mechanism to eliminate a potential double recovery when loads decline. On January 14, 2011, Idaho Power submitted comments in support of a revised methodology for deriving the LGAR rate that was submitted to the IPUC
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for consideration by another utility. Idaho Power’s filing with the IPUC requested a new LGAR rate of $19.36 per MWh, in accordance with the proposed methodology, effective April 1, 2011, representing a 27 percent decrease relative to the current LGAR rate. In the event loads increase relative to normalized levels, the proposed decrease in the LGAR rate would result in Idaho Power collecting a greater amount through the PCA relative to the existing LGAR rate. Conversely, in the event of a load decline the proposed decrease in the LGAR rate would result in Idaho Power collecting lower amounts through the PCA relative to the existing LGAR rate. A determination and order from the IPUC is pending as of the date of this report.
Other Notable IPUC Filings and Orders:
FCA, Pension Expense, AMI, and Energy Efficiency Program: In May 2010, the IPUC issued orders on the following three rate filings:
Fixed Cost Adjustment: In March 2007, the IPUC approved the implementation of an FCA pilot program for Idaho Power’s residential and small general service customers. The FCA is a rate mechanism designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA allows Idaho Power to recover the difference between certain fixed costs recovered in rates and the fixed costs authorized for recovery in Idaho Power’s most recent rate case. The pilot program began on January 1, 2007 and ended on December 31, 2009. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, effective retroactively to January 1, 2010. For the years ended December 31, 2010 and 2009, Idaho Power accrued revenues of $7.5 million and $6.5 million, respectively, under the FCA.
On March 15, 2010, Idaho Power filed an application with the IPUC requesting authorization to implement FCA rates for electric service from June 1, 2010 through May 31, 2011. On May 28, 2010, the IPUC issued an order approving Idaho Power’s request. The rate adjustments are expected to result in collection of an additional $3.6 million over currently billed amounts during the period from June 1, 2010 to May 31, 2011. In its order, the IPUC reiterated a statement in its prior order that making the FCA permanent is premature, and that during the two year extension of the FCA program it expects additional data to develop, giving interested parties and customers time to evaluate the FCA and address issues of concern.
Expense Recovery and Retirement Benefit Plan Prudency: In June 2007, the IPUC issued an order authorizing Idaho Power to account for its defined benefit pension expense on a cash basis. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. By contrast, Idaho Power recovers pension expense in its Oregon jurisdiction on the accrual basis.
In May 2010, the IPUC approved Idaho Power’s request to increase rates to allow recovery of Idaho Power’s 2009 cash contribution to its defined benefit pension plan, which contribution was made in September 2010. Idaho Power’s application sought approval of $5.4 million in pension cost recovery over a one-year period to allow recovery contemporaneous with Idaho Power’s expected cash contributions to the plan. The IPUC’s order permitting recovery further provided that the allowance of recovery of the 2009 pension plan contribution does not guarantee that the IPUC will similarly approve recovery of future pension contributions without evidence that Idaho Power has evaluated alternatives to reduce the burden placed on customers. The IPUC stated in its order that “Idaho Power is advised that, previous orders notwithstanding, approval of Idaho Power’s pension contributions in this case does not guarantee IPUC approval of future pension plan contributions. Authority for the balancing account and regulatory account remain in place. However, further justification is required before additional rate recovery for future contributions will be authorized.” Idaho Power contributed $60 million to the defined benefit pension plan in September 2010.
Following the issuance of the IPUC’s order, Idaho Power undertook its annual review of its current retirement benefits packages, which included a thorough review of costs, benefits, and risks associated with the retirement benefits package, and considered alternatives to its pension plan and
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the weighting of plans between defined benefit and defined contribution. Following that analysis, in September 2010 Idaho Power revised the defined benefit plan for persons hired on or after January 1, 2011 to reduce the company’s estimated cost of the plan for those employees by 20 percent. Costs savings from the change are expected to increase over time as a larger proportion of Idaho Power’s workforce becomes subject to the new benefits calculation. On October 1, 2010, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power’s 2011 retirement benefits package on or before February 28, 2011. Idaho Power’s application did not request recovery through rates of additional pension plan contributions. On December 14, 2010, the IPUC Staff and the Industrial Customers of Idaho Power (ICIP) separately filed comments with the IPUC recommending that the IPUC reject Idaho Power’s request for acceptance of its 2011 retirement benefits package evaluation. The IPUC Staff stated in its comments to the IPUC that, among other items, it believed Idaho Power did not adequately consider available alternatives. On December 28, 2010, Idaho Power filed reply comments noting that based on its analysis it has set its 2011 retirement benefits package at a competitive cost level that is less than the median offerings of similarly situated utility peers, has carefully considered the allocation of costs and investment risk between customers and employees, and the operational imperative to maintain safe, reliable service with an engaged, qualified, experienced, and flexible workforce, and thus requested anew that the IPUC issue an order accepting Idaho Power’s 2011 retirement benefits package. Idaho Power and the IPUC Staff have subsequently submitted additional comments and analysis to the IPUC for consideration. On January 26, 2011, the IPUC issued an order stating that Idaho Power is not precluded from filing for recovery of 2010 contributions before proceedings relating to the 2011 retirement benefits package prudency have concluded. As of the date of this report, a determination and order on the prudency of the 2011 retirement benefits package is pending.
Idaho Power records its deferred pension expense as a regulatory asset. As of December 31, 2010, Idaho Power has a regulatory asset of $2.3 million remaining from the initial $5.4 million of Idaho jurisdiction amount approved for recovery as discussed above. In addition, Idaho Power has Idaho jurisdiction regulatory assets associated with deferred pension expenses of $59.4 million that the IPUC has not approved or denied for recovery. See “Liquidity and Capital Resources - Operating Cash Flows” above in this MD&A for further information relating to Idaho Power’s pension plan, pension funding obligations, and related matters.
Advanced Metering Infrastructure: Idaho Power’s AMI investment during the 2010 test year indicated a revenue deficiency of $2.4 million for the Idaho jurisdiction, which resulted from Idaho Power’s increase in rate base from the AMI deployment, the accelerated depreciation of existing metering equipment, and the inclusion of net operating and maintenance expense related to the AMI deployment. On March 15, 2010, Idaho Power filed an application with the IPUC requesting authority to implement a $2.4 million base rate increase for identified customer classes to recover costs relating to the AMI project. On May 28, 2010, the IPUC approved Idaho Power’s application, authorizing the rate increase effective June 1, 2010. Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for additional information relating to regulatory matters associated with Idaho Power’s AMI investment.
Idaho Energy Efficiency Programs: Idaho Power’s energy efficiency rider is the primary funding mechanism for Idaho Power’s investment in energy efficiency, conservation, and demand response programs. In two separate orders issued in February 2009 and April 2010, the IPUC approved for ratemaking purposes the energy efficiency rider expenditures, totaling $29 million, Idaho Power made from 2002 through 2007. On March 16, 2010, Idaho Power filed an application with the IPUC requesting an order designating energy efficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. On November 16, 2010, the IPUC issued an order designating all $50.7 million of energy efficiency expenditures as prudently incurred and approved for ratemaking purposes.
On May 12, 2010, the IPUC approved Idaho Power’s continued participation in the Northwest Energy Efficiency Alliance for the period 2010-2014, with funding through the energy efficiency rider. Idaho Power first began participating in the Northwest Energy Efficiency Alliance (NEEA) in 1997, and the IPUC has historically allowed it to recover its costs of participation in the program. Idaho Power’s share of expenses is 8.62 percent of the NEEA’s $191.7 million five-year budget that commenced in 2010.
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Idaho Power’s 2010 expenditures for rider-funded energy efficiency and demand response initiatives in its Idaho and Oregon jurisdictions totaled $44.2 million. The trend of increases in spending during the prior several years reflects Idaho Power’s growing emphasis on these programs, such as implementation of a revised irrigation peak rewards program and commercial demand response program.
PURPA Contracts: Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC regulate Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. Projects that generate power below a threshold amount are eligible for the IPUC’s or OPUC’s, as applicable, “Published Avoided Cost” rate, which are based on Idaho Power’s estimated cost of developing additional generating resources. As of the date of this report, the Published Avoided Cost rate is $82.38/MWh. If a PURPA project does not qualify for the Published Avoided Cost rate, then Idaho Power is required to negotiate the terms, prices, and conditions with the developer of that project. Due to the manner in which the Published Avoided Cost rate is calculated and the increase in the number of agreements executed, these PURPA power purchase agreements may result in Idaho Power acquiring energy at above wholesale market prices and at times when a surplus already exists as well as requiring additional operational integration costs, thus increasing costs to Idaho Power’s customers. Substantially all CSPP costs are recovered through base rates and power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates.
On November 5, 2010, Idaho Power and two other electric utilities with Idaho service territories filed a joint motion with the IPUC requesting that the IPUC initiate a docket to investigate and address PURPA-related issues, including the impact on system reliability of PURPA projects, including those that generate intermittent power; operational aspects; the cost of integrating wind generation at large penetration levels; the ownership and valuation of renewable energy certificates (RECs); the lack of capacity provided by intermittent generation resources; associated transmission infrastructure upgrade requirements; and other matters. The motion also sought an interlocutory order adjusting the Published Avoided Cost rate eligibility cap from 10 average MW to 100 kW. On February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for Published Avoided Cost rates, effective retroactively to December 14, 2010, to 100kW for wind and solar PURPA projects only, while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher Published Avoided Cost rates, tax incentives, and other benefits.
Irrigation Peak Rewards Program: On December 10, 2010, Idaho Power filed an application with the IPUC requesting an order authorizing prospective changes to its irrigation peak rewards program. The irrigation peak rewards program is a voluntary load control program available to agricultural irrigation customers, and its purpose is to decrease Idaho Power’s system summer load peak by interrupting service, within specified parameters, to specified irrigation pumps with the use of load control devices between the period from June 15 to August 15 of each year. In exchange for interruption of electric service, participating customers receive a bill credit for usage during the applicable months. Without the program, Idaho Power believes that historically increasing summer peak loads may require the construction of additional power generation facilities, most likely simple-cycle natural gas-fired peaking plants, to meet system load requirements a few hours each year. The cost of the program was $13.3 million and $9.6 million in 2010 and 2009, respectively. Program incentive payments are currently recovered in Idaho and Oregon through the energy efficiency riders. Idaho Power’s application proposes to change the incentive structure for the program from a 100 percent fixed incentive payment methodology to a methodology that combines a 40 percent fixed and 60 percent variable incentive payment to better align annual program costs with capacity needs. If Idaho Power’s application is approved as submitted, Idaho Power estimates program cost savings, based on historical program usage and depending on variables such as the number of participants and number and extent of service interruptions, of up to $7.0 million per year relative to the current program.
Demand-Side Resources Filing: On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company’s demand-side resources (DSR) business model, which included a request for authorization to:
• move demand response incentive payments out of the energy efficiency rider and into the PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA mechanism;
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• establish a regulatory asset for the direct incentive payments associated with Idaho Power’s energy efficiency program for large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentive payments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earn a rate of return on a portion of its DSR activities; and
• change the carrying charge on the existing energy efficiency rider balancing account (from the current interest rate of 1.0 percent to Idaho Power’s authorized rate of return).
Absent IPUC approval of Idaho Power’s proposed modifications, Idaho Power predicts that, based on forecasted revenues and demand-side resource expenditures, the estimated balance of the energy efficiency rider would move from a negative $18 million balance at the end of 2010 to a negative $30 million balance in 2012, and with acceptance of the proposed modifications would approach $0 in mid 2012. Idaho Power’s application did not request a change in customer rates. A hearing on the proposed modifications is scheduled for April 2011.
Eligibility Limits for Larger Customers: On August 26, 2010, Idaho Power filed an application with the IPUC requesting an order authorizing a reduction in the upper eligibility limit for large power service, agricultural irrigation service, and point of delivery service requirements from 25 MW to 20 MW of aggregate load. The reduction in the eligibility limit would permit those customers exceeding 20 MW of aggregate power at one or more points of delivery on the same premises to make special contract arrangements with Idaho Power. By lowering the size limit, Idaho Power believes it can better address service to growing or new load within a special contract, allowing for specific cost-of-service information as well as the unique operating characteristics of customers of this size to be considered and captured within the terms of the agreement. On December 7, 2010, the IPUC issued an order approving Idaho Power’s application. No then-existing Idaho Power customers were impacted by the change in eligibility limits.
Langley Gulch Power Plant Ratemaking Treatment: On September 1, 2009, the IPUC issued an order providing cost recovery and ratemaking assurances related to Idaho Power’s Langley Gulch project. The IPUC found that Idaho Power had satisfied statutory requirements that would entitle Idaho Power to receive such ratemaking assurances and granted Idaho Power assurance and pre-approval to include $396.6 million of construction costs in Idaho Power’s rate base when Langley Gulch achieves commercial operation. The order contemplates that Idaho Power may request recovery of additional costs if they exceed $396.6 million, provided that Idaho Power is able to demonstrate that the additional costs were reasonably and prudently incurred. For further discussion of the Langley Gulch project, see “Liquidity and Capital Resources - Capital Requirements - Major Projects - Langley Gulch Power Plant” in this MD&A.
Oregon Regulatory Matters
Oregon 2009 General Rate Case Settlement: On December 17, 2009, Idaho Power filed a joint stipulation and testimony in support of a stipulation that would settle the revenue requirement issues surrounding the general rate case filed on July 31, 2009. On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates in the Oregon jurisdiction. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. Idaho Power’s previously authorized rate of return in Oregon was 7.83 percent, and its requested rate of return in its general rate case filing was 8.68 percent.
Oregon Power Cost Recovery Mechanisms: Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the PCAM and the APCU. The combination of the PCAM and the APCU allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.
PCAM: The PCAM consists of an annual power supply expense true-up, which uses an asymmetrical deadband (the range of deviations within which Idaho Power absorbs cost increases or decreases) to calculate the net power supply deviations used in the true-up calculations. On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, resulting in no request for a deferral. In an April 15, 2010 stipulation, which was approved in an order issued by the OPUC on May 24, 2010, Idaho Power agreed to a one-time modification to the deadband used to calculate
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the net power supply deviations in the 2010 PCAM. The upper deadband was increased by $0.2 million, to $2.4 million, before any excess power costs are subject to collection pursuant to the terms of the PCAM, and the lower deadband was reduced by $0.2 million, to $(1.0) million, before any power costs are subject to return pursuant to the terms of the PCAM. Idaho Power’s 2010 power supply costs were also within the deadband, resulting in no deferral.
APCU: Idaho Power annually updates its net power supply expense included in its Oregon rates through the APCU. The APCU is comprised of two primary components: an October power cost update and a March power cost forecast. The October update contains Idaho Power’s forecasted net power supply expense reflected on a normalized and unit basis for an April through March test period. The March forecast contains Idaho Power’s net power supply expense based upon updated actual forecasted conditions. The rates from the October update are included in base rates, while the March forecast results in a further update and adjustment to rates. On March 23, 2010, Idaho Power filed its March forecast for the 2010 APCU rate adjustment with the OPUC. A stipulation among various parties combining the March forecast and 2009 October update was filed with the OPUC on April 15, 2010. The stipulation was approved on May 24, 2010, and the rate adjustments are expected to result in collection of an additional $2.2 million over currently billed amounts over the 12-month APCU adjustment period that began on June 1, 2010. On October 15, 2010, Idaho Power filed its October update with the OPUC, requesting an increase in base rates of $1.6 million.
For further information relating to Idaho Power’s Oregon jurisdiction PCA mechanism, refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report.
Oregon Excess Power Cost Deferrals: In May 2009, the OPUC adopted a stipulation allowing Idaho Power to defer excess net power supply costs of $6.4 million (including interest through the date of the order) for the period May 1 through December 31, 2007. Idaho Power recorded the $6.4 million deferral in the second quarter of 2009 as a reduction to power cost adjustment expense. The amount to be recovered was reduced by $0.9 million of previously deferred emission allowance sales (including interest) during the same period. Effective January 2011, these costs began being collected through rates and amortized. Idaho Power expects amortization of this deferral to be completed in February 2014.
Federal Regulatory Matters
As a public utility under the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.
OATT Rates: Idaho Power uses a formula rate for its OATT, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. Idaho Power’s OATT rates for the specified periods were as follows:
Percentage
Period
OATT Rate
Rate Increase
October 1, 2008 to September 30, 2009
$13.81 per kW-year
October 1, 2009 to September 30, 2010
$15.83 per kW-year
14.6%
October 1, 2010 to September 30, 2011
$19.60 per kW-year
23.8%
For the years ended December 31, 2010 and 2009, revenues from the transmission rate for service under the OATT were $15.4 million and $13.3 million, respectively. In September 2010, Idaho Power made corrections to its OATT rates for the period beginning October 1, 2007 through September 30, 2010, which resulted in the issuance of refunds, including interest, to transmission customers of $0.5 million.
FERC OATT Proceedings and ITSA Amendment: The FERC’s acceptance of Idaho Power’s new formula rates in 2006 was subject to refund pending the outcome of a hearing and settlement process. While the majority of issues related to Idaho Power’s 2006 revised OATT filing have been resolved, Idaho Power is awaiting an order upon reconsideration from the FERC regarding the treatment of “Legacy Agreements.” These agreements are contracts for transmission service that were in existence before the implementation of the OATT in 1996. Idaho Power is seeking to mitigate the impact of the FERC’s ruling by negotiating
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revisions to, or seeking alternative arrangements for, certain of the Legacy Agreements as provided for in the agreements.
In June 2009, Idaho Power filed with the FERC a request for authority to increase rates to PacifiCorp under the existing Agreement for Interconnection and Transmission Services (ITSA) between Idaho Power and PacifiCorp to the OATT level. In August 2009, the FERC accepted the rates subject to refund. On May 24, 2010, Idaho Power and PacifiCorp entered into and filed an offer of settlement with the FERC, which settlement affirms those rates. On July 23, 2010, the FERC issued an order approving the ITSA settlement. Under the settlement, PacifiCorp will take and pay for 250 MW of long-term firm point-to-point transmission service, pursuant to the ITSA, the rates, terms, and conditions of which will be equivalent to Idaho Power’s OATT. For the twelve months ended December 31, 2010, revenues were $4.2 million related to the ITSA with PacifiCorp.
FERC Transmission Rate Refunds and Shortfall Filing: On January 15, 2009, the FERC issued an order that required Idaho Power to reduce its transmission service rates to FERC jurisdictional customers and refund $13.3 million to these customers. Based on the FERC order, Idaho Power reserved an additional $7.9 million (including $0.7 million of interest) in 2008 to bring its reserve to the $13.3 million ordered refunded. Idaho Power made the refunds in February 2009 and filed a request for rehearing with the FERC. Of the additional $7.9 million ordered refunded, $2.3 million related to transmission revenues recorded in 2007 and $1.7 million related to transmission revenues recorded in 2006. In March 2009, the FERC issued a tolling order that effectively relieved it from acting within a prescribed period of time on Idaho Power’s request for rehearing. In July 2009, Idaho Power filed an application with the IPUC requesting that the IPUC authorize the deferral of costs associated with transmission service based on transmission costs that could not be recovered in the transmission rate case before the FERC. On February 9, 2011, the IPUC issued an order reducing the deferral amount to $2.1 million, as requested by Idaho Power, and ordering that Idaho Power advise the IPUC when the FERC has issued its order on rehearing. Refer to Note 3 - “Regulatory Matters” to the consolidated financial statements included in this report for further information relating to the OATT shortfall filing and related proceedings with the IPUC.
Triennial FERC Market-Based Rates Tariff Filing: On June 30, 2010, Idaho Power submitted to the FERC its triennial update to its market power analysis in support of its market-based rates tariff showing that Idaho Power’s market-based rate authority should remain in place. FERC noticed the filing on October 21, 2010, but has not yet acted on the filing.
FERC Compliance Program: The FERC issued its Policy Statements on Enforcement in 2005 and 2008 and a Policy Statement on Compliance in 2008. These statements encourage companies to self-report to the FERC matters that constitute or may constitute violations of the FPA, the Natural Gas Act, the Natural Gas Policy Act and the requirements of FERC rules, regulations, orders, and tariffs. The Policy Statements identify self-reporting as a factor the FERC will consider in determining the proper remedy for a violation and emphasize the role compliance programs play in identifying and correcting violations and in evaluating whether and the extent to which penalties may be imposed.
Idaho Power has implemented a compliance program to ensure that its operations conform to the FERC’s requirements and to provide a means of identifying, correcting, and if warranted, self-reporting any such matters to the FERC. Idaho Power also self-reports matters relating to transmission reliability standards to the WECC. In 2007, FERC Order No. 693 approved mandatory reliability standards developed by the North American Electric Reliability Corporation. In 2008, FERC Order No. 706 also approved Critical Infrastructure Protection Reliability Standards (CIP) developed by the North American Electric Reliability Corporation. The WECC, a regional electric reliability organization, has responsibility for compliance and enforcement of these standards. As part of its compliance program, Idaho Power has reported compliance issues relating to the FERC’s Standards of Conduct and Idaho Power’s OATT to the FERC, as well as matters relating to CIP and other reliability standards to the WECC. Some of these matters have been resolved, while others are being reviewed by the FERC or the WECC. Those matters that have been resolved to date have resulted in no material impact to Idaho Power. Idaho Power is unable to predict what action if any the FERC or the WECC will take with regard to the unresolved matters. Idaho Power plans to continue its policy of reducing potential violations through its compliance program and, if warranted, self-reporting compliance issues to the FERC and the WECC.
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Bonneville Power Administration Residential Exchange Program
The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program (REP), has provided access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region’s investor-owned utilities (IOUs). The program is administered by the BPA. Pursuant to agreements between the BPA and Idaho Power, benefits from the BPA were passed through to Idaho Power’s Idaho and Oregon residential and small farm customers in the form of electricity bill credits. However, on May 3, 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that the settlement agreements entered into between the BPA and the IOUs (including Idaho Power) are inconsistent with the Northwest Power Act. As a result, on May 21, 2007, the BPA notified Idaho Power and six other IOUs that it was immediately suspending the REP payments. Idaho Power took action with both the IPUC and the OPUC to reduce the level of credit on its customers’ bills to zero, effective June 1, 2007.
Since that time, Idaho Power has been working with the other northwest IOUs and consumer-owned utilities, northwest state public utility commissions, and the BPA to craft an agreement so that residential and small farm customers of Idaho Power can resume sharing in the benefits of the federal Columbia River power system. The BPA initiated several public processes. Subsequent BPA filings and decisions have provided no REP benefits to Idaho Power’s customers, and Idaho Power and other IOUs filed petitions for review of the BPA’s decisions with the U.S. Court of Appeals for the Ninth Circuit.
Concurrent with the litigation, Idaho Power and other parties engaged in extensive settlement negotiations. As a result of these negotiations, five regional IOUs, including Idaho Power, most consumer-owned utilities, the IPUC, the OPUC, the Washington Utilities and Transportation Commission, and the Citizens’ Utility Board of Oregon signed a non-binding Agreement in Principle, effective as of September 1, 2010, outlining how the REP will be administered by the BPA. The Agreement in Principle created an opportunity for a final settlement agreement to be executed if ultimately agreed upon by the parties. In December 2010, the BPA filed in the REP proceedings a draft settlement agreement between the BPA, entities in the IOU group, certain customer owned utilities, and other parties. The proposed settlement agreement would resolve challenges over BPA’s implementation of the REP in return for a stream of REP benefits to the IOUs for a term of 17 years. In addition to the stream of REP benefits, the IOUs would receive a percentage of certain BPA RECs and the payment of certain outstanding interim payments due under the interim REP payment agreements between BPA and the IOUs. Idaho Power is currently unable to determine the outcome of these proceedings. However, since any benefits, other than any RECs to which Idaho Power may be entitled, would pass directly through to Idaho Power’s eligible residential and small farm customers, the outcome of this matter is not expected to have a significant effect on Idaho Power’s financial condition or results of operations.
Integrated Resource Plan
Idaho Power’s IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans. Idaho Power filed its 2009 IRP with the IPUC and OPUC in December 2009. In August 2010, the IPUC issued an order accepting the IRP for filing. In October 2010, the OPUC issued an order acknowledging the IRP and directing Idaho Power to provide the results of additional analysis and expand the contents of its 2011 IRP. The OPUC requested that Idaho Power analyze, among other things, the impact of coal curtailment and coal plant retirement, the effects of environmental regulations, and treatment of the Boardman to Hemingway transmission project as an uncommitted resource, and requested that Idaho Power provide an updated project analysis on the Boardman to Hemingway transmission project in the 2011 IRP. These actions by the IPUC and the OPUC conclude the regulatory process associated with the 2009 IRP. Idaho Power plans to file its 2011 IRP with regulators in June 2011.
RELICENSING OF HYDROELECTRIC PROJECTS:
Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the HCC and Swan Falls projects (SFP). In addition, in July 2010 Idaho Power received a license
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amendment to expand the Shoshone Falls hydroelectric project and to potentially extend the term of the license beyond its 2034 expiration date.
Hells Canyon Complex: The most significant ongoing relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application for a new license in anticipation of the July 2005 expiration of the then-existing license. In connection with the relicensing process, in August 2007 the FERC Staff issued a final EIS for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes, and the public about the environmental effects of Idaho Power’s operation of the HCC. Certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under section 401 of the Clean Water Act (CWA) and formal consultations under the Endangered Species Act (ESA), which remain unresolved.
Because the HCC is located on the Snake River where it forms the border between Idaho and Oregon, Idaho Power has filed Water Quality Certification Applications, required under section 401 of the CWA, with the States of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Temperature and other water quality issues are of interest to various federal and state agencies, Native American tribes, and other parties who may provide input to the states’ certification process. Section 401 of the CWA requires that a state either approve or deny a 401 water quality certification application within one year of the filing of the application or the state may be considered to have waived its certification authority under the Act. As a consequence, Idaho Power has been filing and withdrawing its section 401 certification applications with Oregon and Idaho on an annual basis while it has been working through water quality certification issues with the states. One such issue involves water temperature control solutions that Idaho Power proposed in its application and whether those solutions provide reasonable assurance that discharges from the HCC will adequately address downstream fall temperature water quality criteria. Idaho Power continues to cooperate with the U.S. Fish and Wildlife Service (USFWS), the National Marine Fisheries Service (NMFS), and the FERC in an effort to address ESA concerns and to work with Idaho and Oregon to take measures to ensure that any discharges from the HCC will comply with the temperature and other applicable state water quality standards so that appropriate water quality certifications can be issued for the project.
On September 13, 2007, in connection with the issuance of its final EIS, FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species under the NMFS’s and USFWS’s jurisdiction and requested that the NMFS and USFWS initiate formal consultation under Section 7 of the ESA on the licensing of the HCC. Each of the NMFS and USFWS responded to the FERC that the conditions relating to the licensing of the HCC were not fully described or developed in the final EIS as the measures to address the water quality effects of the project were yet to be fully defined by the Section 401 certification process pending before the Oregon and Idaho Departments of Environmental Quality. The NMFS and USFWS therefore recommended that formal consultation under the ESA be delayed until the Section 401 certification process is completed.
The FERC is expected to issue a license order for the HCC once the ESA consultation and the state water quality certification processes are completed. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until a new multi-year license is issued.
Swan Falls Project: In June 2008, Idaho Power filed a license application with the FERC for the SFP. The existing license for the SFP expired in June 2010. Idaho Power is currently operating the SFP under an annual license while its application for a multi-year license is pending before the FERC. The FERC issued a final EIS for the SFP in August 2010 and Idaho Power is currently reviewing the final EIS. The final EIS identifies the Snake River Physa snail, which was previously believed to be extinct, as existing in the area. A biological assessment will be conducted and a biological opinion will be issued relating to the Snake River Physa snail prior to the FERC issuing a new license.
Shoshone Falls Expansion: On August 17, 2006, Idaho Power filed a license amendment application with the FERC that would allow Idaho Power to upgrade the Shoshone Falls project from 12.5 MW to 62.5 MW. On July 1, 2010, the FERC amended the license for the Shoshone Falls project to expand its generating
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capacity to 60.875 MW. The amended license has an expiration date of 2034, but provides that the license will be extended to 2044 following completion of the proposed generation capacity expansion project. Idaho Power is evaluating the economic viability of the proposed generation capacity expansion project and is reviewing the associated license requirements and operating issues.
Treatment of Relicensing Costs: Relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $130 million and $5 million for HCC and SFP, respectively, were included in construction work in progress at December 31, 2010. The IPUC currently authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.
LEGAL MATTERS:
Included below is a summary of notable legal proceedings to which IDACORP or Idaho Power are a party. Refer to Note 10 - “Contingencies” to the consolidated financial statements included in this report for further information relating to legal matters and proceedings. Refer to “Environmental Issues” in this MD&A for legal matters pertaining to existing, pending, and potential future environmental laws and regulations.
Western Energy Proceedings at the FERC: Idaho Power and IE are parties to proceedings at the FERC arising from the “western energy situation” - the California energy crisis and the energy shortages, high prices, and blackouts in the western United States during 2000 and 2001 that caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. The three sets of cases arising out of the western energy situation relate to (1) pricing of sales in the California Independent System Operator (Cal ISO) and California Power Exchange (CalPX) markets (the California refund proceeding); (2) claims of market manipulation and tariff violations in those markets, some of which have been the subject of FERC show cause orders (the market manipulation cases); and (3) pricing of sales in the spot power markets in the Pacific Northwest (the Pacific Northwest refund proceeding).
Proceedings in these cases remain pending before the FERC. In addition, there are approximately 200 petitions pending in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) for review of numerous FERC orders regarding the western energy situation, including the California refund proceeding and the market manipulation cases. Decisions in those appeals may have implications with respect to other pending cases, including those to which Idaho Power and IE are parties.
Petitions for review of the scope of the FERC’s market manipulation show cause orders were dismissed with prejudice as to Idaho Power and IE during September through December 2010. However, claims that tariff violations committed by public utility sellers may have affected the market clearing price of sales prior to October 2, 2000 remain pending as part of the California refund proceeding. Idaho Power and IE have reached settlements with the principal parties to the California refund proceeding, but because there remain some parties that have not settled with Idaho Power and IE, a small minority of potential refunds in that proceeding remain subject to the outcome of the litigation. Idaho Power and IE are unable to predict the outcome of these matters, but believe that the settlement releases they have obtained will restrict potential refunds that might result from the disposition of the California refund proceeding and that these matters will not have a material adverse effect on their financial positions, results of operations, or cash flows.
In the Pacific Northwest refund proceeding, after reviewing the FERC’s 2003 decision declining to order refunds, the Ninth Circuit remanded the case to the FERC, officially returning the case to the FERC on April 16, 2009, to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and to include sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the proceedings. In several separate filings the California Parties (consisting of Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the CDWR and the California Attorney General), and the City of Tacoma (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the Pacific Northwest case in different ways to enable them to pursue claims, as
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asserted by the California parties, that all spot market sales in the Cal ISO and CalPX markets and sales to CDWR made in the Pacific Northwest, and, as asserted by Tacoma and Port of Seattle, other sales in the Pacific Northwest from January 1, 2000 through June 20, 2001, should be subject to refund and repriced because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. Idaho Power and IE joined with a number of other sellers in the Pacific Northwest markets in opposing the motions of Tacoma and Port of Seattle and of the California Parties. The FERC has not yet acted on the remand in the Port of Seattle case from the Ninth Circuit or on the filings and requests from the California Parties, Tacoma, and Port of Seattle. Idaho Power and IE are unable to predict the outcome of the Pacific Northwest matters or estimate the impact they may have on their financial positions, results of operations, or cash flows.
Sierra Club Lawsuit and U.S. Environmental Protection Agency (EPA) Notice of Violation at the Boardman Coal-Fired Plant: In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act (CAA), related federal regulations, and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant. Idaho Power cannot determine with certainty the total amount of monetary penalties and damages asserted, but based solely on the complaint the estimated amount is $60 million.
In September 2010, the EPA issued a Notice of Violation to PGE, alleging that PGE has violated the New Source Performance Standards (NSPS) under Section III of the CAA and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations. In the Notice of Violation, the EPA offered PGE an opportunity to confer with the EPA about the violations cited and to present information on the specific findings of the EPA. PGE is scheduled to meet with the EPA regarding the Notice of Violation in March 2011.
Idaho Power is unable to predict the outcome of these matters or estimate the impact they may have on its consolidated financial position, results of operations, or cash flow.
Snake River Basin Water Rights: Idaho Power holds water rights, acquired under applicable state law, for all water used in its hydroelectric projects. However, Idaho Power’s water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses. In the late 1970’s and early 1980’s, reduced water flows resulted in a conflict between the exercise of Idaho Power’s water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. In 1987, the State of Idaho initiated the Snake River Basin Adjudication (SRBA), pursuant to which all claimants to water rights within the Snake River basin were required to file water right claims in the SRBA. Idaho Power has filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the effect of existing agreements pertaining to Idaho Power’s water right claims resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009. In the Framework, the parties acknowledged that the effective management of Idaho’s water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho’s water resources. Idaho Power continues its active participation in the SRBA in seeking to ensure that its water rights are protected and that the operation of its hydroelectric projects is not adversely impacted.
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While Idaho Power cannot predict the outcome, Idaho Power does not currently anticipate any materially adverse modification of its water rights as a result of the SRBA process. For additional information on the SRBA, see Note 10 - “Contingencies - Water Rights - Snake River Basin Adjudication” to the consolidated financial statements included in this report.
Idaho Power also filed an action in the U.S. District Court of Federal Claims in Washington, D.C. in October 2007, and an amended complaint on September 30, 2008, against the U.S. Bureau of Reclamation (USBR) relating to a 1923 spaceholder contract right for storage and delivery of water to Idaho Power from American Falls Reservoir, a USBR storage reservoir on the Snake River. Idaho Power’s complaint claims damages for the lost generation resulting from the reduced flows downstream of the reservoir, and asks for a prospective declaration of the rights and obligations of the parties under the 1923 contract. Idaho Power has been working with the USBR and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve the contested contract issues that are common to both the SRBA and the pending federal case with the USBR. In an effort to promote judicial efficiency, the parties agreed to stay the pending federal case and present certain legal issues associated with the 1923 contract to the court in the SRBA case, the resolution of which are expected to resolve issues in the pending federal case. These issues were presented to the SRBA court through motions for summary judgment, which were argued in December 2010. However, as the parties continue to pursue a negotiated resolution to the 1923 contract issues, they have requested that the SRBA withhold any ruling on the motions pending the outcome of ongoing settlement negotiations. Idaho Power is unable to predict the outcome of this matter or what effect it may have on its financial position, results of operations, or cash flows. For additional information on the SRBA, see Note 10 - “Contingencies - U.S. Bureau of Reclamation Proceedings” to the consolidated financial statements included in this report.
For further information regarding other pending legal proceedings, see Note 10 - “Contingencies” to the consolidated financial statements included in this report.
ENVIRONMENTAL ISSUES:
Overview: Idaho Power is subject to regulations by federal, state, and local authorities governing the protection of the environment, including at the federal level the CAA; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the Federal Land Policy and Management Act; the National Environmental Policy Act; and the Resource Conservation and Recovery Act. These laws and regulations are continually changing and are generally becoming more restrictive. Idaho Power monitors legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to alter the operation and productivity of power generating plants and other assets. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power discontinue operating certain power generation plants. While there can be no assurance of recovery, Idaho Power intends to seek recovery of any such costs through the ratemaking process.
Idaho Power continues to actively monitor pollution control standards as they are promulgated and their associated costs to Idaho Power as they relate to the economic and operational feasibility of operation of generation plants. In its order acknowledging Idaho Power’s 2009 IRP, the OPUC has required that Idaho Power analyze (a) any potential EPA, state, and other federal agency regulations associated with air quality, fly ash, and water that may affect Idaho Power’s generation facilities, and (b) coal curtailment and the costs associated with coal plant retirement, and include the results of this analysis in its 2011 IRP. While not currently quantifiable, Idaho Power anticipates that a number of impending EPA rulemakings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs.
Global Climate Change: There is concern nationally and internationally about global climate change and the possible contribution of greenhouse gas (GHG) emissions to climate change. Long-term climate change could significantly affect Idaho Power’s business in a variety of ways, including the following: (i) changes in temperature and precipitation could affect customer demand; (ii) extreme weather events could increase service interruptions, outages, maintenance costs, and the need for additional systems backup, and can affect
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the supply of, and demand for, electricity and natural gas, which may impact the price of energy commodities; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation; (iv) legislative and/or regulatory developments related to climate change could affect plans and operations, including by placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general; and (v) consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission infrastructure. Idaho Power does not currently operate in coastal areas and, while there may be secondary impacts such as increased supply chain costs, it is not directly exposed to the effects of potential sea level rises that some experts predict may result from global climate change.
Greenhouse Gas Emission Reduction Goals: Despite the current absence of a national mandatory GHG reduction program, Idaho Power is engaged in voluntary GHG reduction efforts. In September 2009, IDACORP’s and Idaho Power’s boards of directors approved guidelines that established a goal to reduce the CO2 emission intensity of Idaho Power’s utility operations. Idaho Power’s goal is to reduce its resource portfolio’s average CO2 emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power’s 2005 CO2 emission intensity of 1,194 lbs CO2/MWh. The guidelines are intended to reduce Idaho Power’s average CO2 emission intensity in a manner that minimizes the costs of those reductions to Idaho Power’s customers. In May 2010, Idaho Power submitted information to the Carbon Disclosure Project, an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. Idaho Power’s estimated CO2 emission intensity (lbs/MWh) from its generation facilities as submitted to the Carbon Disclosure Project was 1,150, 1,097, and 1,004 lbs/MWh for 2007, 2008, and 2009, respectively. Idaho Power estimates that its CO2 emission intensity from its generation facilities was approximately 1,050 lbs CO2/MWh in 2010.
In 2008, Idaho Power and Ida-West together ranked as the 32nd lowest emitter of CO2/MWh produced among the nation’s 100 largest electricity producers, according to a June 2010 collaborative report from Ceres, the Natural Resources Defense Council, Public Service Enterprise Group, Constellation Energy, and Entergy using publicly reported 2008 generation and emissions data. According to the report, out of the 100 companies named, Idaho Power and Ida-West together ranked as the 55th largest power producer based on fossil fuel, nuclear, and renewable energy facility total electricity generation, and the 31st lowest emitter of CO2 by tons of emissions.
Regulation of Greenhouse Gas Emissions: In recent years, there have been a number of bills introduced in the U.S. Congress relating to GHG emissions, renewable energy, energy efficiency, carbon capture and sequestration, and other matters. However, given the complexities of this form of legislation and other competing legislative priorities, the timing and elements of any future legislation addressing GHG emission reduction requirements are uncertain. There are also state and regional initiatives (including the Western Regional Climate Action Initiative) considering market-based mechanisms to reduce GHG emissions.
In support of international efforts to reduce GHG emissions, in January 2010 U.S. President Barak Obama pledged to cut GHG emissions in the United States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. Any international treaty creating mandatory GHG emission reduction requirements in the United States would need to be ratified by the U.S. Senate and implemented through legislation adopted by the U.S. Congress.
In September 2009, the EPA issued a final rule that required monitoring and reporting of GHG emissions by a number of entities beginning on January 1, 2010. Most facilities are required to report annually. Electric generation facilities (including Idaho Power’s facilities) already reporting CO2 emissions under the CAA Acid Rain Program must report CO2, nitrogen oxide (NOx), and methane emissions to the EPA on a quarterly basis. In March 2010, the EPA proposed to expand the monitoring and reporting requirements to include emissions of fluorinated GHGs such as sulfur hexafluoride from electrical power transmission and distribution systems.
In June 2010, the EPA issued a final rule regulating GHG emissions through its preconstruction and operating permit programs under the CAA. This rule is referred to as the “Tailoring Rule.” The first phase of the rule took effect on January 2, 2011 and requires imposition of Best Available Control Technology (BACT) for GHG emissions if a new major source or modification of an existing major source is projected to result in GHG emissions of at least 75,000 tons per year (CO2 equivalent). In addition, existing major
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sources will need to amend their operating permits to include applicable requirements relating to GHGs. On November 10, 2010, the EPA released guidance on what technologies would be considered BACT for GHGs from stationary sources applying for Prevention of Significant Deterioration (PSD) permits under the CAA. The EPA has elected not to identify what control technologies are best suited to reducing GHG emissions, but rather to require a “case-by-case” analysis. These regulatory provisions may ultimately be nullified if Congress enacts GHG legislation that preempts regulations promulgated by the EPA. The EPA’s effort to regulate GHG emissions through the CAA’s permitting programs has been appealed to the U.S. Court of Appeals for the District of Columbia Circuit. On December 10, 2010, the court denied motions to stay the EPA’s GHG regulatory program. This allowed the GHG regulation under the PSD and Title V programs of the CAA to go into effect as scheduled on January 2, 2011, while the appeals of the rules proceed to briefing on the merits. On December 23, 2010, the EPA announced that it will propose GHG emission standards for power plants in July 2011 under the NSPS program.
In August 2007, the Oregon legislature enacted legislation establishing goals for the reduction of GHG emissions, which sought to cease the growth of Oregon GHG emissions by 2010, and seek to (i) by 2020, reduce GHG levels to 10 percent below 1990 levels; and (ii) by 2050, reduce GHG levels to at least 75 percent below 1990 levels. The legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals.
On December 6, 2010, the U.S. Supreme Court granted certiorari in Connecticut v. American Electric Power Inc., to review the opinion from the U.S. Court of Appeals for the Second Circuit granting plaintiffs standing to bring climate change-related public nuisance suits against six major emitters of GHGs. Were the Court to determine that climate change-related public nuisance suits could be viable, costs to owners and operators of coal-fired or gas-fired power plants could be significant as a result of court’s imposing standards that could require significant capital expenditures, fuel switching, or facility closures to achieve compliance.
Idaho Power will continue to monitor and evaluate proposed international, federal, state, and regional GHG legislation or initiatives as well as judicial decisions that could affect its generating facilities and operations. Some recent initiatives regarding GHG emissions contemplate market-based compliance programs, such as cap-and-trade programs or emission offsets. The regulation of GHG emissions under the CAA could result in GHG emission limits on stationary sources that do not provide market-based compliance options. Such a program could raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities because new technologies for reducing CO2 emissions from coal, including carbon capture and storage, are still in the development stage and are not yet proven. Emission standards could require significant increases in capital expenditures and operating costs, which may accelerate the retirement of older, less-efficient coal-fired units. In its December 23, 2010 announcement of plans to develop GHG emission standards under the NSPS program for power plants and petroleum refineries, the EPA stated that it would proceed with such regulation in a “measured and careful” manner.
There are financial, regulatory, and logistical uncertainties related to GHG reductions and the implementation of renewable energy mandates. The impact on Idaho Power of currently proposed legislation relating to GHG emissions would depend on a variety of factors, including the specific GHG emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through rates. Accordingly, Idaho Power cannot meaningfully predict the effect on its results of operations, financial position, or cash flows of any GHG emission, renewable energy mandate, or other global climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. Idaho Power would seek to recover these costs and expenditures from customers as costs of doing business but is unable to predict whether it would be permitted to recover some or all of the increased costs and expenditures from customers through rates.
However, to the extent GHG emissions are regulated through a federal GHG emissions program, Idaho Power believes its business could also benefit. Idaho Power’s generation fleet has an overall CO2 emission rate that is lower than the industry average with a substantial amount of the fleet's output coming from
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hydroelectric plants, which generate significantly lower CO2 emissions than fossil fuel plants. Such regulatory initiatives may also lead to increased opportunities associated with renewable generation and alternative fuels.
In its 2009 IRP, Idaho Power did not include any new conventional coal resources in the resource portfolio due to the uncertainty regarding future GHG regulations. IDACORP and Idaho Power’s boards of directors continue to review environment issues on a regular basis and in connection with the review of the companies’ strategic plans. The boards of directors are also periodically informed of any new material environmental issues, including updates on any proposed legislation.
Renewable Standards: A bill that passed in the U.S. House of Representatives in June 2009 would require utilities to obtain 20 percent of their electricity from renewable sources by 2020, and reduce demand an additional 5 percent through conservation and increased energy efficiency. A bill relating to renewable energy standards (RES) that was introduced in the Senate in September 2010 would require utilities to acquire 3 percent of their power from renewable resources beginning in 2012, increasing to 15 percent by 2021, and as proposed would not count existing hydroelectric power generation towards meeting the new RES. Idaho Power will be required to comply with a 10 percent RPS in Oregon beginning in 2025. Idaho Power expects to meet these requirements with the RECs from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal RES legislation, which if passed could increase Idaho Power’s capital expenditures and operating costs and reduce earnings and cash flows.
Oregon Solar Photovoltaic Energy Pilot Program: Pursuant to rules adopted by the OPUC in 2010 implementing the Oregon Legislature’s mandate for availability of solar photovoltaic energy programs to Oregon customers, Idaho Power is required to (1) either build or purchase an aggregate of 500 kW of energy from one or more solar facilities by the year 2020; and (2) purchase energy from qualified solar photovoltaic systems at a financial incentive rate of 55 cents per kWh to promote the development of 10 kW and smaller solar projects over a two year period. The program is to be rolled out over a two-year period for a total nameplate capacity of 400 kW. The legislative mandate and the OPUC orders specify that the cost of these programs be paid by Oregon customers. Idaho Power’s costs of participation in the program, currently estimated to be $0.6 million per year, are being deferred and collected from Oregon customers through a rider mechanism.
Renewable Energy and PURPA Contracts: As of December 31, 2010, Idaho Power had contracts to purchase energy from 18 on-line wind projects with a combined nameplate rating of 395 MW. At that date, Idaho Power also had signed and approved PURPA contracts to purchase energy from an additional 12 wind projects with a combined nameplate rating of 283 MW. These projects are expected to be online between mid-2011 and the end of 2012. In addition, at December 31, 2010, Idaho Power had pending for possible approval before the IPUC contracts with 16 wind projects with a combined nameplate capacity of 369 MW. Idaho Power is in contract discussions with a number of developers regarding additional PURPA wind projects.
Idaho Power has entered into an agreement for the purchase of energy from a geothermal electric generation facility under development near Vale, Oregon, with an estimated 22 MW output and expected on-line date of late 2012. Idaho Power has contracted to receive the RECs from the project during the term of the agreement. In June 2010, Idaho Power entered into a 20 year PURPA power purchase agreement with the owner of a proposed solar power generation facility, which is expected to have a 20-MW nameplate capacity and an expected online date of December 2011. In September 2010, the IPUC approved Idaho Power’s entry into the power purchase agreement. In July 2010, Idaho Power entered into a 15 year PURPA firm energy sales agreement with the owner of a biomass plant with an expected nameplate capacity of 10 MW and online date of December 2011. Idaho Power has also entered into a number of other PURPA agreements for smaller renewable energy projects.
In May 2009, Idaho Power issued a request for proposals (RFP) seeking to purchase approximately 150 MW of wind-powered generation by 2012. In August 2010, Idaho Power closed its RFP without awarding a contract, determining that the RFP no longer provided a competitive resource as a result of changes in the wind energy market and lower energy prices available from a large wind Qualifying Facility, under a negotiated power purchase agreements. In response to a shift in the size, number, and scale of PURPA projects seeking power purchase contracts, on November 5, 2010, Idaho Power and two other utilities jointly filed a request for the
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IPUC to open a case to investigate and address the cost-effectiveness of resources acquired through PURPA. Idaho Power anticipates that current and proposed PURPA projects could generate more power than the minimum load experienced on Idaho Power’s system during 2010, which could result in problems with system operations and reliability. On February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap on the size of wind and solar projects that qualify for the published avoided cost rates from 10 average MW per month to 100 kW per month while an investigation of PURPA project disaggregation is under way.
Idaho Power is selling its near-term RECs and returning to customers their share of those proceeds through the PCA. Idaho Power filed a REC Management Plan with the IPUC in December 2009 to address its treatment of future RECs. Under Idaho Power’s REC Management Plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future RES requirements. For the year ended December 31, 2010, Idaho Power’s REC sales totaled $4.5 million. Idaho Power has sold all of its 2009 and earlier vintage RECs. Idaho Power has sold a portion of its 2010 RECs and intends to continue selling its 2010 and later RECs as they are generated and become available for sale. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects.
Idaho Power continues to pursue additional geothermal, wind, biomass, and combined heat and power generation resource development opportunities. Other generation resource types anticipated from future small power production contracts include solar, biomass, and additional wind projects.
Air Quality: Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. The coal-fired plants are Jim Bridger (one third interest) located in Wyoming; Boardman (10 percent interest) located in Oregon; and Valmy (50 percent interest) located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. Additionally, Idaho Power is currently in the process of constructing the Langley Gulch power plant, a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. Idaho Power continues to actively monitor, evaluate, and work on air quality issues pertaining to federal and state mercury emission rules, possible legislative amendment of the CAA, National Ambient Air Quality Standards (NAAQS), and Regional Haze - Best Available Retrofit Technology (RH BART) and New Source Review (NSR) permitting.
Mercury Emissions: Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy plants and, as of the date of this report, tests to confirm the accuracy of the data being collected are underway. The EPA has announced that it is developing maximum achievable control technology (MACT) standards to reduce mercury emissions from coal-fired power plants. Early indications are that these MACT standards will apply uniformly to all coal-fired power plants, unlike the cap-and-trade mercury standards of the Clean Air Mercury Rule. In 2008, the State of Oregon adopted a mercury rule requiring the Boardman plant to reduce mercury emissions by 90 percent or meet an emission rate of 0.6 lbs/trillion BTU by July 2012. Idaho Power continues to monitor Wyoming and Nevada actions related to mercury emissions. Idaho Power is unable to predict at this time what actions the EPA or the other states may take to reduce mercury emissions from its coal-fired power plants. In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that would require the EPA to propose a standard to control mercury emissions from coal-fired power plants by May 2011 and to finalize it by November 2011.
National Ambient Air Quality Standards (NAAQS): In July 1997, the EPA adopted new NAAQS for ozone (8-hour ozone standard) and fine particulate matter of less than 2.5 micrometers in diameter (PM2.5 standard). In December 2006, the EPA revised the NAAQS for PM2.5. This new standard is the subject of a legal challenged by a number of groups. However, all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power’s power plants operate currently were designated as meeting attainment with the revised PM2.5 NAAQS. In January 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a 1-hour period. In addition, in June 2010 the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. The EPA has not yet designated areas as attaining or not attaining these new NAAQS. Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations.
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Regional Haze - Best Available Retrofit Technology: In accordance with federal regional haze rules, coal-fired utility boilers are subject to RH BART if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. The two units at the Valmy plant were constructed after 1977 and are not subject to the federal regional haze rule. The Wyoming Department of Environmental Quality (WDEQ) and the Oregon Department of Environmental Quality (ODEQ) have conducted assessments of the Jim Bridger and Boardman plants pursuant to an RH BART process. These states have also evaluated the need for additional controls at Jim Bridger and Boardman to achieve reasonable progress toward a long term strategy beyond RH BART to reduce regional haze in Class I areas to natural conditions by the year 2064.
On December 31, 2009, the WDEQ issued a RH BART permit to PacifiCorp for the Jim Bridger plant. The WDEQ determined that low NOx burners with over-fire air is RH BART for NOx for all four Bridger units and that RH BART is not required for SO2 for the Jim Bridger plant. As part of the WDEQ’s long term strategy for regional haze, the permit requires that PacifiCorp install selective catalytic reduction (SCR) for NOx control at Jim Bridger Units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NOx controls at Jim Bridger Units 1 and 2 by December 31, 2023. PacifiCorp is already in the process of installing low NOx burners and SO2 scrubber upgrades at the Jim Bridger plant. The SO2 scrubber upgrade project has been completed on Jim Bridger Units 2 and 4 and is expected to be completed on the other two units by the end of 2011. Idaho Power expects to spend approximately $22 million between 2009 and 2012 to complete these projects. Idaho Power’s estimated share of the cost to install SCR on Jim Bridger Units 3 and 4 is $120 million. Installation of SCR also could require extended maintenance outages. Design and cost estimates for add-on NOx controls at Jim Bridger Units 1 and 2 are not yet available. On February 26, 2010, PacifiCorp filed an administrative appeal of the Jim Bridger RH BART permit with the Wyoming Environmental Quality Council (WEQC). PacifiCorp argued that the WDEQ lacked the legal and technical basis to require the SCR and add-on NOx controls required by the permit. On September 9, 2010, the WEQC denied a motion for summary judgment filed by PacifiCorp challenging the WDEQ’s legal authority to require SCR installation at Jim Bridger. On November 3, 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp has agreed to install SCR, alternative add-on NOx controls, or otherwise achieve a 0.07 lb/mmBtu 30-day rolling average NOx emission rate by December 31, 2015 for Unit 3 and December 31, 2016 for Unit 4. In addition, PacifiCorp has agreed to install SCR, alternative add-on NOx controls, or otherwise achieve a 0.07 lb/mmBtu 30-day rolling average NOx emission rate by December 31, 2021 for Unit 2 and December 31, 2022 for Unit 1. The settlement agreement is conditioned on the EPA ultimately approving those portions of the Wyoming Regional Haze State Implementation Plan that are consistent with the terms of the settlement agreement. In light of the settlement agreement, WDEQ issued a revised RH BART permit for Jim Bridger on November 24, 2010.
In June 2009, the Oregon Environmental Quality Commission (OEQC) adopted a rule that would require the installation of controls at the Boardman plant in two phases. Idaho Power’s estimated share of the aggregate cost of the pollution control requirements for RH BART and the long term strategy under the June 2009 rule were between approximately $52 million and $56 million. In April 2010, PGE submitted a petition requesting that the OEQC reconsider the RH BART and long term strategy requirements for the Boardman plant to be the installation of low NOx burners and over-fire air by July 1, 2011, the phased transition to reduced sulfur coal by December 31, 2011 and July 1, 2014, and the closure of Boardman plant coal-fired boiler by December 31, 2020. In June 2010, the OEQC denied PGE’s April 2010 proposed plan. In August 2010, PGE submitted to the ODEQ a new plan that would cease coal-fired operations at the Boardman plant in 2020, but contemplated additional emission reductions relative to PGE’s previous 2020 closure plan. Following an extensive public process, in December 2010, the OEQC approved PGE’s August and October 2010 plan to cease coal-fired operations at the Boardman plant not later than December 31, 2020. The new rules implementing the plan are expected to contain the following measures:
• installation of new low- NOx burners and modified overfire air ports by July 2011 to comply with BART standards for oxides of nitrogen;
• installation of a dry sorbent injection system by July 2014 to comply with BART standards for sulfur dioxide (SO2);
• pilot studies for the Direct Spark Ignition system to verify that set SO2 limits for 2014 and 2018 are achievable;
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repeal of the ODEQ’s 2009 BART rule, which would have allowed continued operation of the Boardman plant through at least 2040 with installation of a much more expensive suite of emissions controls; and
permanent cessation of coa-fired operation no later than December 31, 2020.
The revised rules have been submitted to the EPA for its consideration and approval. The estimated combined total capital cost of the required controls under the plan approved by the OEQC is approximately $60 million. Idaho Power is a 10 percent owner of the Boardman plant, and thus Idaho Power’s estimated share of the capital costs is $6 million. At December 31, 2010, Idaho Power’s net book value in the Boardman plant was approximately $19.8 million with annual depreciation of approximately $1.2 million. Idaho Power plans to spend approximately $4 million on capital investment at Boardman in 2011.
While not required under RH BART, installation of low NOx burners and over-fired upgrades has been completed at the Valmy plant.
New Source Review (NSR): Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the NSR permitting requirements and NSPS of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The current U.S. administration has indicated an intention to continue this NSR enforcement initiative. The EPA sent information requests under the CAA, requesting information relevant to NSR and NSPS compliance, to the Jim Bridger plant in 2003, the Valmy plant in 2009, and the Boardman plant in 2008 with a follow up request for information in 2009. Idaho Power is a co-owner of, but does not operate, these plants. As discussed above, on September 28, 2010, the EPA issued a Notice of Violation to PGE, alleging that PGE has violated the NSPS under Section III of the CAA and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of certain modifications made to the plant in 1998 and 2004. Idaho Power cannot predict the outcome of these investigatory and enforcement matters at this time.
Coal Combustion Residuals (CCRs): In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash into a nearby river and onto private properties. In June 2010, the EPA proposed regulations pursuant to the Resource Conservation and Recovery Act governing the disposal and management of CCRs. The EPA requested comments on two options for regulating CCRs. The first would regulate CCRs as a new “special waste” subject to many of the requirements for hazardous waste, while the second would regulate CCRs in a manner similar to typical solid waste, subject to fewer and less stringent environmental requirements. The EPA initiated a public comment period and held public hearings in 2010. Either of the EPA’s proposed options represents a shift toward more comprehensive and potentially more expensive requirements for CCRs disposal and management. If this or other new legislation or regulations increase the cost of managing and disposing of CCRs or create additional liability with respect to historic disposal practices, they could have an adverse impact on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final legislation is passed or regulations are enacted.
Polychlorinated Biphenyls (PCBs): In April 2010, the EPA issued an advance notice of proposed rulemaking pursuant to the Toxic Substances Control Act regarding the use of PCBs. The EPA is considering revisiting the use authorization allowing the continued use of PCBs in equipment. If new regulations require the replacement of existing equipment, they could have an adverse effect on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final regulations are enacted. Idaho Power currently records asset retirement obligation liabilities and associated regulatory assets for the estimated retirement costs of equipment containing PCBs. Proposed regulations could accelerate Idaho Power’s estimated timing of the retirements of equipment with PCBs.
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Endangered Species:
Slickspot Peppergrass: This southwestern Idaho plant species was listed as threatened by the USFWS effective December 2009. While critical habitat for the plant was not designated at the time of listing, approximately 98 percent of the plant species is located on federal land owned by the U.S. Bureau of Land Management (BLM) and the U.S. Department of Defense. Parts of the Gateway West and Boardman to Hemingway 500-kV transmission lines and the Langley Gulch transmission and water lines will cross BLM land. This listing will add an additional requirement and species for consideration in the ESA Section 7 consultation. A Section 7 consultation is a process used to determine a proposed action’s effects on any ESA-listed species that may be within the project area. This listing may increase the expense and delay the timing of permitting for these projects.
Sage Grouse: On March 5, 2010, the USFWS announced that listing of the greater sage grouse as threatened or endangered under the ESA is warranted, but precluded by higher priority listing actions. The sage grouse is now considered a “candidate species” under the ESA, which allows land management agencies to implement additional conservation measures in an effort to prevent a formal ESA listing. Due to the presence of sage grouse in the vicinity, siting of Idaho Power’s Boardman to Hemingway and Gateway West 500-kV transmission lines has required more extensive, costly, and time consuming evaluation and engineering. Any required additional conservation measures may increase the costs of existing operations and impact the cost and timing of siting and permitting of the Boardman to Hemingway and Gateway West transmission lines and other construction and transmission projects. Listing of the greater sage grouse as threatened or endangered under the ESA would add an additional requirement and species for consideration in ESA Section 7 consultations for those projects, and may increase the expense and adversely affect the cost and timing of those projects.
Hells Canyon Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the National Marine Fisheries Service (NMFS) and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has not yet been initiated and NMFS and USFWS continue to gather and consider information relative to the effects of relicensing on relevant species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Idaho Power may be required to modify operations pursuant to the biological opinion that will result from formal consultation. However, the issuance of a final biological opinion during 2011 is unlikely.
Bliss and Lower Salmon Falls Projects: Idaho Power has finalized a snail protection plan in cooperation with the USFWS. Idaho Power has filed applications with the FERC to amend the licenses for the Bliss and Lower Salmon Falls projects that will maintain operating flexibility at both projects for the remainder of their licenses.
Swan Falls Project: Idaho Power is currently operating the SFP under an annual license while its application for a multi-year license is pending before the FERC. In August 2010, the FERC issued a final EIS in connection with the relicensing. The Snake River Physa snail, which was previously believed to be extinct, was discovered during the EIS review. As a result, a biological assessment will be conducted and biological opinion relating to the Physa snail will be issued as a component of Idaho Power’s relicensing efforts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES:
When preparing financial statements in accordance with generally accepted accounting principles (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates.
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Management believes the following accounting policies and estimates are the most critical 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 and may change in subsequent periods.
Accounting for Rate Regulation
Entities that meet specific conditions are required by GAAP to reflect the impact of regulatory decisions in their consolidated financial statements and to defer certain costs as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy three conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service territory must lack competitive pressures to reduce rates below the rates set by the regulator.
Idaho Power has determined that it meets these conditions, and its financial statements reflect the effects of the different rate making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power has recorded $759 million of regulatory assets and $306 million of regulatory liabilities at December 31, 2010. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power would be required to eliminate those regulatory assets or liabilities, unless regulators specify some other means of recovery or refund. Either circumstance could have a material effect on Idaho Power’s results of operations and financial position.
Income Taxes
IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.
Idaho Power’s deferred income taxes for plant-related items (commonly referred to as normalized accounting) are primarily provided for the difference between income tax depreciation and book depreciation used for financial statement purposes. Unless contrary to applicable income tax guidance, deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.
In September 2009, the IRS issued IDD #5, which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return.
The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than Idaho Power’s prior method, resulting in a tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of current year tax expense from the reversal of this temporary difference. Idaho Power has provided a current uncertain tax position liability equal to the $59.7 million net tax benefit recorded for the method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes. IDACORP and Idaho Power cannot predict exactly when such approval will occur, but believe it is reasonably possible during fiscal year 2011.
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Asset Impairment
Available-for-sale Securities: Idaho Power is required to evaluate available-for-sale securities periodically to determine whether a decline in fair value below cost is other than temporary. If the decline in fair value is other than temporary, the cost of the investment is written down to fair value and the loss is recorded as a realized loss. Two significant factors that are considered when evaluating investments for impairment are the length of time and the extent to which the market value has been less than cost.
Idaho Power has investments in four mutual funds that experienced a significant decline in fair value in 2008. Idaho Power’s investments had lost between 32 percent and 43 percent of their value, primarily during the stock market downturn in September and October 2008, and had been in loss positions from 6 to 12 months at December 31, 2008. Because of the severity of the declines in value, Idaho Power determined that the loss in value was other-than-temporary and recorded a pre-tax loss of $6.8 million in the fourth quarter of 2008. At December 31, 2010 and 2009, the fair value of these investments was above their new cost basis and no impairment was recorded.
Equity-Method Investments: IFS has affordable housing investments with a net book value of $74 million at December 31, 2010, and Ida-West has investments in four joint ventures that own electric power generation facilities. Except for one investment which is consolidated, these investments are accounted for under the equity method of accounting. The standard for determining whether impairment must be recorded for these investments is whether the investment has experienced a loss in value that is considered an other-than-temporary decline in value. Impairment analyses are performed on these investments when indicators of impairment are noted. No impairments were recorded in 2010 and in 2009 an immaterial impairment was recorded on one of the Ida-West joint ventures. These estimates required IDACORP to make assumptions about future revenues, cash flows, and other items that are inherently uncertain. Actual results could vary significantly from the assumptions used, and the impact of such variations could be material.
Pension and Other Postretirement Benefits
Idaho Power maintains a tax-qualified, noncontributory defined benefit pension plan covering most employees, an unfunded nonqualified deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP), and a postretirement benefit plan (consisting of health care and death benefits).
The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets, and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future stock market performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates.
The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power utilize data published in the Citigroup Pension Liability Index and apply the rates therein against the projected cash outflows of the plans. The discount rate used to calculate the 2011 pension expense will be decreased to 5.4 percent from the 5.9 percent used in 2010.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher. The long-term rate of return used to calculate the 2011 pension expense will remain at the 8.25 percent rate used for 2010.
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Gross pension and other postretirement benefit expense for these plans totaled $39 million, $40 million, and $16 million for the three years ended December 31, 2010, 2009, and 2008, respectively, including amounts allocated to capitalized labor and amounts deferred as regulatory assets. For 2011, gross pension and other postretirement benefit costs are expected to total approximately $39 million, which takes into account the change in the discount rate noted above, as well as a decrease in expected return on plan assets. No changes were made to the other key assumptions used in the actuarial calculation.
Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:
No cash contributions were made to the defined benefit pension plan in 2008 or 2009. A $6 million contribution for 2009 was due in calendar year 2010. In September 2010 Idaho Power elected to make a $60 million contribution to the defined benefit pension plan. A $3 million contribution for 2010 is due in calendar year 2011. Estimated payments of $46 million, $36 million, $32 million, and $31 million are due in 2012, 2013, 2014, and 2015, respectively. Under the SMSP, Idaho Power makes payments directly to participants in the plan. Benefit payments are expected to be $3.4 million in 2011 and averaged $3.1 million per year from 2008 to 2010. Postretirement benefit plan contributions are expected to be $3.8 million in 2011, and averaged $2.5 million from 2008 to 2010.
The IPUC has authorized Idaho Power to account for its defined benefit pension plan expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. The deferral of pension expense began in 2007. At December 31, 2010, $64 million of expense was deferred as a regulatory asset. Approximately $27 million is expected to be deferred in 2011. Idaho Power recorded pension expense in 2010, 2009, and 2008 of $4.5 million, $1.3 million, and $0 million, respectively.
Refer to Note 11 - “Benefit Plans” of the consolidated financial statements included in this report for additional information relating to pension and postretirement benefit plans.
Contingent Liabilities
An estimated loss from a loss contingency is charged to income if (a) it is probable that a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. If a probable loss cannot be reasonably estimated, no accrual is recorded but disclosure of the contingency in the notes to the financial statements is required. Gain contingencies are not recorded until realized.
IDACORP and Idaho Power have a number of unresolved issues related to regulatory and legal matters. If the recognition criteria have been met, liabilities have been recorded. Estimates of this nature are highly subjective and the final outcome of these matters could vary significantly from the amounts that have been included in the financial statements.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
See Note 1 - “Summary of Significant Accounting Policies” to the consolidated financial statements included in this report for a discussion of recently issued accounting pronouncements.
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INFLATION
IDACORP and Idaho Power believe that inflation has caused and may continue to cause increases in certain operating expenses and the replacement of assets at higher costs. Inflation affects the cost of labor, products, and services required for operations and maintenance and capital expenditures. While inflation has not had a significant impact on IDACORP’s or Idaho Power’s operations, increases in utility expenses due to inflation could have an adverse effect on earnings because of the need to obtain regulatory approval to recover such increased expenses, and there can be no assurance that applicable regulators will permit such recovery.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in 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, 2010.
Interest Rate Risk
IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may be used to achieve the desired combination.
Variable Rate Debt: As of December 31, 2010, IDACORP and Idaho Power, after netting with short term investments, had no floating rate debt.
Fixed Rate Debt: As of December 31, 2010, IDACORP and Idaho Power each had $1.6 billion in fixed rate debt, with a fair market value also equal to $1.6 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $150 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their December 31, 2010 levels.
Commodity Price Risk
Idaho Power’s exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. These purchased power arrangements allow Idaho Power to respond to fluctuations in the demand for electricity and variability in generating plant operations. Idaho Power also enters into arrangements for the purchase of fuel for natural gas and coal-fired generating plants. Idaho Power anticipates that the additional volume of natural gas needed to operate the Langley Gulch power plant will increase its exposure in the future to natural gas commodity price risk. These contracts for the purchase of power and fuel expose Idaho Power to commodity price risk.
A number of factors associated with the structure and operation of the energy markets influence the level and volatility of prices for energy commodities and related derivative products. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of production. Other factors include the occurrence and timing of demand peaks due to seasonal, daily, and hourly power demand; power supply; power transmission capacity; changes in federal and state regulation and compliance obligations; fuel supplies; and market liquidity.
Idaho Power’s exposure to commodity price risk is largely offset by the PCA mechanisms in Idaho and Oregon. Therefore, the primary objectives of Idaho Power’s energy purchase and sale activity are to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop. Idaho Power has adopted a risk management program, which has been reviewed and accepted by the IPUC, designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. Idaho Power’s Energy Risk Management
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Policy (Policy) and associated standards implementing the Policy describe a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of selected Idaho Power officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho Power Board of Directors and to the CAG, and Idaho Power’s Audit Committee is responsible for approving the Policy and associated standards. The RMC is also responsible for conducting an ongoing general assessment of the appropriateness of Idaho Power’s strategies for energy risk management activities. In its risk management process, Idaho Power considers both demand-side and supply-side options consistent with its IRP. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources. Idaho Power does not engage in trading activities for non-retail purposes.
The Policy requires monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The Power Supply business unit produces and evaluates projections of the operating plan based on factors such as forecasted resource availability, stream flows, and load, and orders risk mitigating actions, including resource optimization and hedging strategies, dictated by the limits stated in the Policy to bring exposures within pre-established risk guidelines. The RMC evaluates the actions initiated by Power Supply for consistency and compliance with the Policy. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the board of directors for approval.
Credit Risk
Utility: Idaho Power is subject to credit risk based on its activity with market counterparties. Idaho Power 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. Idaho Power 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. Idaho Power maintains a current list of acceptable counterparties and credit limits.
The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements that allow performance assurance collateral to be requested and/or posted with certain counterparties. As of December 31, 2010, Idaho Power had posted approximately $4.6 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to forward contracts and derivative instruments could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and current market conditions as of December 31, 2010, the approximate amount of additional collateral that could be requested upon a downgrade is approximately $17 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.
Idaho Power is obligated to provide service to all electric customers within its service area. Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC or OPUC. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power will continue to monitor the impact of the current economic conditions on nonpayment from customers and will make any necessary adjustments to its provision for uncollectible accounts.
Idaho administrative code for utility customer relations rules prohibits Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly, or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC or OPUC regulations.
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Equity Price Risk
IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity investments at Idaho Power. As a result of market increases in 2010, the fair value of the defined benefit pension plan’s assets increased; however, increases in the benefit liabilities were greater than the increases in the plan’s assets, therefore resulting in an increase in future amounts required to be contributed to the plan. Based on current laws, Idaho Power estimates that the minimum contribution to the defined benefit pension plan in 2011 will be $3.0 million. A hypothetical ten percent decrease in equity prices would result in an approximate $2.5 million decrease in the fair value of financial instruments that are classified as available-for-sale securities as of December 31, 2010.
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
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IDACORP, Inc.
Consolidated Balance Sheets
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IDACORP, Inc.
Consolidated Balance Sheets
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IDACORP, Inc.
Consolidated Statements of Cash Flows
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IDACORP, Inc.
Consolidated Statements of Equity
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IDACORP, Inc.
Consolidated Statements of Comprehensive Income
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Idaho Power Company
Consolidated Statements of Income
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Idaho Power Company
Consolidated Balance Sheets
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Idaho Power Company
Consolidated Balance Sheets
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Idaho Power Company
Consolidated Statements of Capitalization
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Idaho Power Company
Consolidated Statements of Cash Flows
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Idaho Power Company
Consolidated Statements of Retained Earnings
Idaho Power Company
Consolidated Statements Comprehensive Income
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IDACORP, INC. AND Idaho POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, the Notes to the Consolidated Financial Statements apply to both IDACORP and Idaho Power. However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.
Nature of Business
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities that wound down operations in 2003.
Principles of Consolidation
IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.
The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). Marysville has approximately $20 million of assets, primarily a hydroelectric plant, and approximately $16 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.
Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary. IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner. The carrying value of BCC is $90 million at December 31, 2010, and the maximum exposure to loss at BCC is the carrying value, any additional future contributions to the mine, and the $63 million guarantee for reclamation costs at the mine that is discussed further in Note 9 - “Commitments.”
Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from five to 99 percent. As a limited partner, IFS does not control these entities and they are not consolidated. These investments were acquired between 1996 and 2010. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $74 million at December 31, 2010.
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Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues, and bad debt. 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 Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, and Wyoming.
Regulation of Utility Operations
IDACORP’s and Idaho Power’s financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power. The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would. In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. The effects of applying these regulatory accounting principles to Idaho Power’s operations are discussed in more detail in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporary investments that mature within 90 days of the date of acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed periodically and adjusted based upon a combination of historical write-off experience, aging of accounts receivable, and an analysis of specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after reasonable collection efforts are written off through a charge to the allowance and a credit to accounts receivable.
Other receivables, primarily notes receivable from business transactions, are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that IDACORP or Idaho Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for the estimated uncollectible portion of the receivable and charged to income. The following table summarizes IDACORP’s other receivables and related allowances for the years ended December 31, 2010 and 2009 (in thousands of dollars):
There were no impaired receivables without related allowances at December 31, 2010 and 2009. Once a receivable is determined to be impaired, any further interest income recognized is fully reserved.
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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. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet. Idaho Power’s physical forward contracts qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities. The objective of the risk management program is to mitigate the price risk associated with the purchase and sale of electricity and natural gas. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.
Revenues
Operating revenues related to Idaho Power’s sale of energy are recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at period-end. Idaho Power collects franchise fees and similar taxes related to energy consumption. None of these collections are reported on the income statement. Beginning in February 2009, Idaho Power is collecting in base rates a portion of the allowance for funds used during construction (AFUDC) related to its Hells Canyon relicensing project, as discussed in Note 3. Cash collected under this ratemaking mechanism is not recorded as revenue, but is instead recorded as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. 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 2.84 percent in 2010, 2.81 percent in 2009, and 2.73 percent in 2008.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment must be recognized in the financial statements. There were no material impairments of these assets in 2010, 2009, or 2008.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. Idaho Power’s weighted-average monthly AFUDC rates for 2010, 2009, and 2008 were 8.0 percent, 6.7 percent, and 5.2 percent, respectively. Idaho Power’s reductions to interest expense for AFUDC were $11 million for 2010, $5 million for 2009, and $7 million for 2008. Other income included $17 million, $8 million, and $3 million of AFUDC for 2010, 2009, and 2008, respectively.
Income Taxes
IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
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Consistent with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction over Idaho Power’s Idaho service territory, Idaho Power’s deferred income taxes for plant-related items (commonly referred to as normalized accounting) are primarily provided for the difference between income tax depreciation and book depreciation used for financial statement purposes. Unless contrary to applicable income tax guidance, deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods direct Idaho Power to recognize the tax impact currently for rate-making and financial reporting. 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.
The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits 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.
Income taxes are discussed in more detail in Note 2.
Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities, and amounts related to a deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP).
The following table presents IDACORP’s and Idaho Power’s accumulated other comprehensive loss balance at December 31 (net of tax):
Other Accounting Policies
Debt discount, expense, and premium are deferred and are being amortized over the terms of the respective debt issues.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications did not impact IDACORP’s and Idaho Power’s net income or total equity. Reclassifications include the following:
other accrued taxes, that are not income tax accruals, were removed from taxes accrued and included in other current liabilities in the IDACORP consolidated balance sheets. Taxes accrued and taxes receivable were relabeled in IDACORP and Idaho Power’s consolidated balance sheets to be income taxes accrued and income taxes receivable, respectively, to provide greater comparability between statements;
uncertain tax positions are presented separately and are no longer included within other current liabilities on IDACORP and Idaho Power’s consolidated balance sheets as the uncertain tax positions were material as of December 31, 2010;
amortization of affordable housing was removed from depreciation and amortization and combined with undistributed earnings of unconsolidated subsidiaries, the total of which was then separated into losses of unconsolidated equity-method investments and distributions from unconsolidated equity method investments in the operating section of IDACORP’s consolidated statements of cash flows; and
immaterial line item balances have been combined for presentation with similar account balances or activities.
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Adopted Accounting Pronouncements
IDACORP and Idaho Power adopted the following Financial Accounting Standards Board (FASB) pronouncements in 2010:
• in January 2010, IDACORP and Idaho Power adopted amendments to prior consolidation guidance. The amendments affected the overall consolidation analysis of VIEs and required IDACORP and Idaho Power to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether either IDACORP or Idaho Power are the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. The adoption of this guidance did not change the entities that IDACORP or Idaho Power consolidate; and
• in July 2010, the FASB issued guidance that significantly expands the required disclosures concerning the credit quality of certain types of receivables and the allowance for credit losses. This guidance is effective for IDACORP and Idaho Power as follows: (1) disclosures concerning end-of-period information were effective for these financial statements; and (2) disclosures about activity occurring during a reporting period are effective beginning with the quarter ending March 31, 2011. Because this guidance relates only to disclosures, it did not and is not expected to have a material effect on IDACORP’s and Idaho Power’s consolidated financial statements.
2. INCOME TAXES:
The components of the net deferred tax liability are as follows:
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A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
The items comprising income tax (benefit) expense are as follows:
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IDACORP’s tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP.
Tax Credits Carryforwards and Net Operating Loss Carryforwards
As of December 31, 2010, IDACORP had $95.8 million of general business credit carryforward for federal income tax purposes and $24.5 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2024 to 2030, and the Idaho investment tax credit expires from 2019 to 2024. IDACORP has a $57.7 million Idaho net operating loss carryforward which expires in 2029.
Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits for IDACORP and Idaho Power is as follows (in thousands of dollars):
If recognized, the $74.4 million balance of unrecognized tax benefits at December 31, 2010 would affect the effective tax rate.
IDACORP and Idaho Power recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. Both companies recognized interest expense of $0.2 million in 2010, and a net reduction in interest expense of $0.2 million and $0.1 million in 2009 and 2008, respectively. As of December 31, 2010, both companies had accrued interest of $0.2 million and none as of December 31, 2009. No penalties are accrued.
IDACORP and Idaho Power are subject to examination by their major tax jurisdictions - U.S. federal and the State of Idaho. The open tax years are 2009-2010 for federal and 2007-2010 for Idaho. In May 2009, IDACORP formally entered the Internal Revenue Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. With the exception of Idaho Power’s capitalized repairs and uniform capitalization tax accounting methods (discussed below), IDACORP and Idaho Power believe there are no remaining tax uncertainties for the 2009 tax year and expect that the 2009 examination may conclude during fiscal year 2011.
Tax Accounting Method Change for Repair-Related Expenditures
In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return.
For the year ended December 31, 2010, Idaho Power recorded a $44.5 million tax benefit related to the filed deduction for the cumulative method change adjustment and an additional $11.7 million tax benefit for the annual deduction estimate included in its 2010 income tax provision. As of December 31, 2010, Idaho Power had a current uncertain tax position liability of $14.7 million related to this method. The estimated annual tax deduction related to capitalized repairs produces a net tax benefit of $9 million annually, which is approximately $5 million higher than Idaho Power’s prior repair deduction method reported in 2009. The reversal of this temporary difference will offset a portion of the ongoing annual benefit.
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Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse.
The tax method is currently being audited under IDACORP’s 2009 CAP examination and, on a national level, aspects of the method related to electric utility generation, transmission, and distribution property are the subject of an IRS Industry Issue Resolution program.
Tax Accounting Method Change for Uniform Capitalization
In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return. Due to the method change agreement with the IRS, Idaho Power reversed the uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for the year ended December 31, 2010.
The resulting tax deductions available under the agreed upon uniform capitalization method are significantly greater than Idaho Power’s prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of current year tax expense from the reversal of this temporary difference. The prescribed regulatory accounting treatment for this method is the same as discussed earlier for the capitalized repairs method.
As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal to the $59.7 million net tax benefit recorded for the method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes.
Cash Impacts of Tax Method Changes
IDACORP and Idaho Power have realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. The majority of this cash benefit has been realized through reductions to cash payments that would have otherwise been owed to taxing authorities for the 2009 tax year and a federal refund of $24 million received in the fourth quarter of 2010. Additionally, approximately $6 million of state cash benefits were realized through reduced tax payments for the 2010 year.
The capitalized repairs and uniform capitalization method changes produced an income statement tax benefit of $44.5 million and $65.3 million, respectively, prior to the accrual for uncertain tax positions. A portion of this earnings benefit relates to previously deferred income tax expense being flowed through the income statement, which does not deliver any cash benefits. In addition, federal tax credits of $17 million previously recognized were restored due to the reduction of 2009 taxable income by the two method changes. The restored credits were a reduction to cash received in 2010, but will be available to deliver cash benefits in future periods.
Tax Impacts of Health Care Acts
As discussed further in Note 11, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. As a result of this legislation, in the first quarter of 2010 Idaho Power reduced its deferred tax asset related to future Medicare Part D deductible retiree prescription drug expenses by $2.3 million, increased regulatory assets by $2.4 million, increased deferred tax liabilities by $1 million, and incurred a charge of $0.9 million.
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3. REGULATORY MATTERS:
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric assets. The following table presents a summary of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):
The majority of Idaho Power’s regulatory assets and liabilities are reflected in customer rates and are amortized over the period in which they are reflected in customer rates. In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a significant financial impact.
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Deferred Net Power Supply Costs
Deferred power supply costs are recorded as a deferred charge on the balance sheets for future recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Idaho Power and the costs included in retail rates. This difference in net power supply costs primarily results from changes in short-term wholesale market prices and sales and purchase volumes, the level of hydroelectric generation, the level of thermal generation, and retail loads. Changes in deferred power supply costs over the last two years were as follows:
Idaho Jurisdiction Power Cost Adjustment Mechanism:
In the Idaho jurisdiction, Idaho Power has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. The PCA tracks Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. The annual PCA adjustments are based on two components:
• a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates; and
• a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast. This component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. The true-up component is calculated monthly, and interest is applied to the balance.
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The following table summarizes PCA rate adjustments in the three years ended December 31, 2008, 2009, and 2010:
In its order approving Idaho Power’s 2008-2009 PCA, the IPUC directed Idaho Power to set up workshops with the IPUC Staff and several of Idaho Power’s largest customers to address issues not resolved in that PCA filing. The workshops resulted in the following changes to the PCA mechanism:
PCA sharing ratio - the PCA allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent). The previous sharing ratio was 90/10;
LGAR - the LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The 2007 general rate case reset the LGAR from $29.41 to $62.79 per MWh, but applied that rate to only 50 percent of the load growth beginning in March 2008. The stipulation agreed on a new formula for calculating the LGAR. Based on the final rates approved by the IPUC, as of the date of this report the LGAR is $26.63 per MWh;
use of Idaho Power’s operation plan power supply cost forecast - the operation plan forecast may better match current collections with actual net power supply costs in the year they are incurred and result in smaller amounts being included in the following year’s “true-up” rate, beginning with the 2009-2010 PCA filing;
inclusion of third-party transmission expense - transmission expenses paid to third parties to facilitate wholesale purchases and sales of energy, including losses, are a necessary component of net power supply costs. Deviation in these costs from levels included in base rates is now reflected in PCA computations; and
adjusted distribution of base net power supply costs - base net power supply costs are distributed throughout the year based upon the monthly shape of normalized revenues for purposes of the PCA deferral calculation.
In the IPUC’s May 2010 order implementing new PCA rates for the period from June 1, 2010 to May 31, 2011, the IPUC identified the use of the LGAR in times of load decline as an issue of contention. However, the IPUC Staff recommended no change to the load growth adjustment amounts or methodology, and the IPUC did not remove the LGAR adjustment to the PCA component. The IPUC’s order stated, however, that it expects the IPUC Staff, Idaho Power, and interested parties to meet to address an appropriate change to the LGAR mechanism to eliminate a potential double recovery when loads decline. On January 14, 2011, Idaho Power submitted to the IPUC comments in support of a revised methodology that was submitted for consideration by another utility. Idaho Power’s filing with the IPUC requested a new LGAR rate of $19.36 per MWh under the revised methodology effective April 1, 2011. As of the date of this report, a determination and order from the IPUC is pending.
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Oregon Jurisdiction Power Cost Adjustment Mechanism:
Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the annual power cost update (APCU) and the power cost adjustment mechanism (PCAM). The combination of the APCU and the PCAM allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.
The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The APCU has two components: the “October Update,” Idaho Power’s calculation of estimated normalized net power supply expenses for the following April through March test period, and the “March Forecast,” Idaho Power’s forecast of expected net power supply expenses for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices.
Base power supply cost changes since inception are as follows:
Year
APCU Description
Idaho Power’s October Update portion of the 2011 APCU indicates that revenues associated with Idaho Power’s base net power supply costs would be increased by $1.6 million over the current rates. The actual impact will be determined once the March Forecast portion is filed in March 2011 and combined with the October Update. Final rates are expected to become effective on June 1, 2011.
A rate increase of $2.6 million annually took effect June 1, 2010.
A rate increase of $3.9 million annually took effect June 1, 2009
A rate increase of $4.8 million annually took effect June 1, 2008
The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that it results in Idaho Power’s actual return on equity (ROE) for the year being no greater than 100 basis points below Idaho Power’s last authorized ROE. A refund to customers will occur only to the extent that it results in Idaho Power’s actual ROE for that year being no less than 100 basis points above Idaho Power’s last authorized ROE. Results of the PCAM since inception are as follows:
Year
PCAM Description
Actual net power supply costs were within the deadband, resulting in no deferral.
Actual net power supply costs were within the deadband, resulting in no deferral.
Actual net power supply costs exceeded the forecast for the 2008 calendar year by $7.7 million and, after application of the deadband, resulted in a $5.1 million deferral in 2008. The OPUC approved deferral of this amount in January 2010, to be amortized sequentially after previously authorized deferrals.
Oregon Excess Power Cost Deferrals:
In May 2009, the OPUC adopted a stipulation allowing Idaho Power to defer excess net power supply costs of $6.4 million (including interest through the date of the order) for the period May 1 through December 31, 2007. Idaho Power recorded the $6.4 million deferral in the second quarter of 2009 as a reduction to power cost adjustment expense. The amount to be recovered was reduced by $0.9 million of previously deferred SO2emission allowance sales (including interest) during the same period. Effective January 2011, these costs are being collected through rates and amortized.
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Fixed Cost Adjustment Mechanism (FCA)
The FCA mechanism began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009. The FCA is a rate mechanism designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, effective retroactively to January 1, 2010.
On May 29, 2010, the IPUC approved the recovery of $6.3 million of under-recovered fixed costs related to 2009, with rates effective June 1, 2010 through May 31, 2010. In May 2009, the IPUC approved FCA rates effective June 1, 2009 through May 31, 2010, to recover $2.7 million of fixed costs under-recovered during 2008. In 2008, the IPUC approved a rate reduction, effective June 1, 2008 through May 31, 2009, to return $2.4 million of fixed costs over-recovered in 2007.
Idaho Rate Cases
Idaho 2009 Settlement Agreement and 2010 PCA Order: On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others. Significant elements of the settlement agreement include:
a general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the PCA, the FCA, pension funding, advanced metering infrastructure (AMI), energy efficiency rider, and government imposed fees;
a specified distribution of the reduction in 2010 PCA that would reduce customer rates, provide up to a $25 million general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCA rate change. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year;
a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011; and
a provision to allow the accelerated amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power's actual rate of return on equity is below 9.5 percent in any calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power would be permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.
Because Idaho Power’s Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent in 2009 and 2010, the sharing and accelerated amortization provisions were not triggered. In accordance with the settlement, Idaho Power has available $25 million of additional ADITC amortization for use in 2011.
On April 15, 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010 through May 31, 2011, and to change base rates, pursuant to the terms of the January 2010 Idaho settlement agreement. On May 28, 2010, the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The net effect of these two rate adjustments was an overall decrease in customer rates of $58.2 million, effective June 1, 2010. The $88.7 million base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in base rates.
Idaho 2008 General Rate Case: On January 30, 2009, the IPUC issued an order approving an average annual increase in Idaho base rates, effective February 1, 2009, of 3.1 percent (approximately $20.9 million annually), a return on equity of 10.5 percent, and an overall rate of return of 8.18 percent. On February 19, 2009, Idaho Power filed a request for reconsideration with the IPUC and on March 19, 2009, the IPUC issued an order that increased Idaho Power’s Idaho revenue requirement by an additional $6.1 million to approximately $27 million for this rate case, raising the average rate increase from 3.1 percent to 4.0 percent.
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The January 30, 2009 order authorized approximately $15 million related to increases in base net power supply costs. It also allowed Idaho Power to include in rates approximately $6.8 million ($10.6 million including income tax gross-up) of 2009 AFUDC relating to the Hells Canyon Complex relicensing project. Typically, AFUDC is not included in rates until a project is in use and benefitting customers, but the IPUC determined that including this amount in current rates is in the public interest. Because AFUDC is already recorded on an accrual basis, this portion of the rate increase will improve cash flows but will not have a current impact on Idaho Power’s net income. The amounts collected are being deferred as a regulatory liability and will be recognized in revenues over the life of the new license once it has been issued.
The IPUC denied reconsideration with respect to a refund of $3.3 million of fees recovered by Idaho Power from the FERC. On April 2, 2009, Idaho Power filed an application with the IPUC for an accounting order approving amortization of the fees over a five-year period beginning October 2006 when Idaho Power received the FERC credit. The IPUC approved Idaho Power’s requested amortization period in an order issued on April 28, 2009. In the first quarter of 2009, Idaho Power recorded a charge of approximately $1.7 million to electric utility other operations expense and a corresponding regulatory liability for the amount to be refunded from February 1, 2009, through the end of the amortization period, September 2011. As the regulatory liability is amortized it reduces electric utility other operations expense ratably over the remaining amortization period.
Idaho Danskin CT1 Power Plant Rate Case: On May 30, 2008, the IPUC authorized Idaho Power to add to its rate base $64.2 million for the Danskin CT1 plant and related facilities, effective June 1, 2008, resulting in a base rate increase of 1.37 percent, or $8.9 million in annual revenues. Danskin CT1 is located near Mountain Home, Idaho and began commercial operations on March 11, 2008.
Retirement Benefits Plan: Idaho Power defers its pension expense as a regulatory asset. Idaho Power deferred approximately $24 million, $29 million, and $8 million of pension expense to a regulatory asset in 2010, 2009, and 2008, respectively. Deferred pension costs are expected to be amortized to expense to match the revenues received when future pension contributions are recovered through rates. Idaho Power only records a carrying charge recorded on the unrecovered balance of cash contributions.
In May 2010, the IPUC approved Idaho Power’s request to increase rates to allow recovery of Idaho Power’s 2009 cash contribution to its defined benefit pension plan, which contribution was made in September 2010. Idaho Power’s application sought approval of $5.4 million in pension cost recovery over a one-year period to allow recovery contemporaneous with Idaho Power’s expected cash contributions to the plan. In the IPUC’s May 2010 order approving an increase in rates to allow recovery of $5.4 million of Idaho Power’s $60 million contribution made in September 2010 to the defined benefit pension plan, the IPUC stated that “Idaho Power is advised that, previous orders notwithstanding, approval of Idaho Power’s pension contributions in this case does not guarantee IPUC approval of future pension plan contributions. Authority for the balancing account and regulatory account remain in place. However, further justification is required before additional rate recovery for future contributions will be authorized.”
Following the issuance of the IPUC’s order, Idaho Power undertook its annual review of its current retirement benefits packages, which included a thorough review of costs, benefits, and risks associated with the retirement benefits package, and considered alternatives to its pension plan and the weighting of plans between defined benefit and defined contribution. Following that analysis, in September 2010 Idaho Power revised the defined benefit plan for persons hired on or after January 1, 2011 to reduce the company’s estimated cost of the plan for those employees by 20 percent. On October 1, 2010, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power’s 2011 retirement benefits package on or before February 28, 2011. On December 14, 2010, the IPUC Staff and the Industrial Customers of Idaho Power (ICIP) filed comments with the IPUC recommending that the IPUC reject Idaho Power’s request for acceptance of its 2011 retirement benefits package evaluation. The IPUC Staff stated in its comments to the IPUC that, among other items, it believed Idaho Power did not adequately consider available alternatives. On December 28, 2010, Idaho Power filed with the IPUC reply comments to the IPUC Staff’s and ICIP’s comments. In its reply comments, Idaho Power noted that based on its analysis it has set its 2011 retirement benefits package at a competitive cost level that is less than the median offerings of similarly situated utility peers, has carefully considered the allocation of costs and investment risk between customers and employees, and the operational imperative to maintain safe, reliable service with an engaged, qualified, experienced, and flexible workforce, and thus requested anew that the IPUC issue an order accepting Idaho
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Power’s 2011 retirement benefits package. On January 26, 2011, the IPUC issued an order stating that Idaho Power is not precluded from filing for recovery of 2010 contributions before proceedings relating to the 2011 retirement benefits package prudency have concluded.
Idaho Energy Efficiency Rider: On March 16, 2010, Idaho Power filed an application with the IPUC requesting an order designating energy efficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. On November 16, 2010, the IPUC issued an order designating all $50.7 million of energy efficiency expenditures as prudently incurred and approved for ratemaking purposes. Idaho Power’s 2010 expenditures for rider-funded energy efficiency and demand response initiatives in its Idaho and Oregon jurisdictions totaled $44.2 million.
Langley Gulch Power Plant Ratemaking Treatment: On September 1, 2009, Idaho Power received pre-approval from the IPUC to include $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch power plant achieves commercial operation. Idaho Power may request recovery of additional costs if they exceed $396.6 million, provided that the additional costs were reasonably and prudently incurred.
Oregon Rate Cases
Oregon 2009 General Rate Case: On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates in the Oregon jurisdiction. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. Idaho Power’s previously authorized rate of return in Oregon was 7.83 percent and its requested rate of return in the general rate case filing was 8.68 percent.
Other Regulatory Proceedings
Advanced Metering Infrastructure: The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense.
On February 12, 2009, the IPUC approved Idaho Power’s application requesting a Certificate of Public Convenience and Necessity for the deployment of AMI technology and approval of accelerated depreciation for the existing metering equipment. The IPUC subsequently clarified that Idaho Power can expect to include in rate base the Idaho portion of prudent capital costs of deploying AMI as it is placed in service up to the capital cost commitment estimate of $70.9 million, plus certain costs that the company could not quantify with precision at the time of the application. The IPUC also clarified, as requested by Idaho Power, that it does not anticipate that the immediate savings derived from the implementation of AMI throughout Idaho Power’s service territory will eliminate or wholly offset the increase in Idaho Power’s revenue requirement caused by the authorized depreciation period.
On May 29, 2009, the IPUC approved annual recovery of $10.5 million, effective June 1, 2009. The order was based on Idaho Power’s actual investment in AMI through the then-current date, annualized through December 31, 2009. The IPUC also allowed Idaho Power to begin three-year accelerated depreciation of the existing metering equipment on June 1, 2009. The order reflects annualized depreciation expense relating to AMI of $9.2 million. Actual depreciation expense recorded in 2010 and 2009 were $10.6 million and $6.2 million, respectively.
On March 15, 2010, Idaho Power filed an application with the IPUC requesting authority to implement a $2.4 million base rate increase for identified customer classes to recover costs relating to the AMI project. On May 28, 2010, the IPUC approved Idaho Power’s application, authorizing the rate increase effective June 1, 2010.
In the Oregon jurisdiction, the OPUC approved accelerated depreciation and recovery of existing meters located in Oregon over an 18-month period beginning January 2009. Idaho Power has substantially completed the deployment of the Oregon service-territory meters. The existing meters were fully depreciated prior to their removal from service. The approval increased both rates and depreciation expense $0.8 million in 2009 and $0.4 million in 2010.
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Depreciation Filings: In 2008 and 2009 Idaho Power filed revisions to its depreciation rates with the IPUC, the OPUC, and the FERC. The commissions approved the new rates, which reduce depreciation expense approximately $8.5 million annually. Idaho Power began applying the new depreciation rates in August 2008.
Federal Regulatory Matters
Open Access Transmission Tariff (OATT) Rates: In 2006, Idaho Power moved from a fixed rate to a formula rate for its OATT, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. On August 28, 2009, Idaho Power filed its annual informational filing with the FERC that contains the annual update of the formula rate based on the 2008 test year. The new rate included in the filing was $15.83 per kW-year, an increase of $2.02 per kW-year, or 14.6 percent. The rates were effective from October 1, 2009 through September 30, 2010. On August 26, 2010, Idaho Power submitted its annual information filing for its OATT to FERC. The new rate submitted by Idaho Power was $19.60 per kW/year and was effective as of October 1, 2010 for a period of one year. For the years ended December 31, 2009 and 2010, revenues from the transmission rate for service under the OATT were $13.3 million and $15.4 million, respectively. In September 2010, Idaho Power made corrections to its OATT rates for the period beginning October 1, 2007 through September 30, 2010, which resulted in the issuance of refunds, including interest, to transmission customers of $0.5 million.
FERC OATT Proceedings and ITSA Amendment: On May 24, 2010, Idaho Power and PacifiCorp entered into and filed an offer of settlement with the FERC in connection with Idaho Power’s request for authority to increase rates to PacifiCorp under the existing Agreement for Interconnection and Transmission Services (ITSA). Under the settlement, which the FERC approved in July 2010, PacifiCorp will take and pay for 250 MW of long-term firm point-to-point transmission service, pursuant to the ITSA, the rates, terms, and conditions of which will be equivalent to Idaho Power’s OATT. For the twelve months ended December 31, 2010, Idaho Power collected $4.2 million related to the ITSA with PacifiCorp.
FERC Transmission Rate Refunds and Shortfall Filing: On January 15, 2009, the FERC issued an order that required Idaho Power to reduce its transmission service rates to FERC jurisdictional customers and refund $13.3 million to these customers. Based on the FERC order, Idaho Power reserved an additional $7.9 million (including $0.7 million of interest) in 2008 to bring its reserve to the $13.3 million ordered refunded. Idaho Power made the refunds in February 2009 and filed a request for rehearing with the FERC. Of the additional $7.9 million ordered refunded, $2.3 million related to transmission revenues recorded in 2007 and $1.7 million related to transmission revenues recorded in 2006. In March 2009, the FERC issued a tolling order that effectively relieved it from acting for an indefinite period of time on Idaho Power’s request for rehearing.
For Idaho jurisdictional revenue requirement determinations, revenues from third parties (non-state jurisdictional) received through the OATT, referred to as revenue credits, are a direct offset to Idaho Power’s overall revenue requirement. In the last two general rate cases, Idaho Power included an estimate of OATT revenues from third parties based on the forecasted OATT rate. However, the FERC order issued on January 15, 2009 reduced actual third-party transmission revenues Idaho Power received starting in June 2006, resulting in an overstatement of the revenue credits in the Idaho jurisdictional revenue requirement.
On October 30, 2009, the IPUC approved Idaho Power’s request for authorization to defer the difference between the revenue credits in the last two general rate cases and the amount of OATT revenues Idaho Power has received since March 2008 and expected to receive through May 2010. The IPUC order authorized Idaho Power to amortize the unrecovered transmission revenues on a straight-line basis over a three-year period beginning January 1, 2011 and did not authorize a carrying charge on the balance. Based on actual and projected transmission revenues from March 2008 through May 2010, Idaho Power recorded a $4.7 million regulatory asset in 2009 for potential future recovery.
On October 13, 2010, Idaho Power refreshed its filing with the IPUC for its deferral related to unrecovered transmission revenues. Termination of a transmission arrangement with PacifiCorp and adjustments to other transmission arrangements allowed Idaho Power to reduce its prior deferral amount to $2.1 million. Idaho Power requested to begin amortization of the $2.1 million deferred amount on January 1, 2012, rather than January 1, 2011, as originally ordered, because Idaho Power’s settlement agreement would not permit
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potential inclusion of the deferral amount in rates until after January 1, 2012. On February 9, 2011, the IPUC issued an order reducing the deferral amount to $2.1 million, as requested by Idaho Power, but denied the request to begin amortization on January 1, 2012, instead ordering that Idaho Power advise the IPUC when the FERC has issued its order on rehearing. Thereafter, Idaho Power may request a commencement date for the three-year amortization period.
4. LONG-TERM DEBT
The following table summarizes long-term debt at December 31:
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At December 31, 2010, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):
IDACORP Long-Term Financing
As of December 31, 2010, IDACORP has approximately $539 million remaining on a shelf registration statement filed with the Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or common stock. Common stock is discussed further in Note 6.
Idaho Power Long-Term Financing
In May 2010, Idaho Power registered with the SEC the sale of up to $500 million of first mortgage bonds and debt securities. On June 17, 2010, Idaho Power entered into a selling agency agreement with ten banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds. On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under the shelf registration statement. As of December 31, 2010, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.
Mortgage: As of December 31, 2010, Idaho Power could issue under its Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R.G. Page, as Trustees (Stanley Burg, successor individual trustee) (Mortgage) approximately $407 million of additional first mortgage bonds based on total unfunded property additions of approximately $679 million. Idaho Power could issue an additional $612 million of first mortgage bonds based on retired first mortgage bonds. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the Mortgage.
The Mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority, or distinction. First mortgage bonds issued in the future will also be secured by the Mortgage. The lien of the indenture constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen’s compensation awards, and similar encumbrances and minor defects and clouds common to properties. The Mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The Mortgage creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger, or sale of all or substantially all of the assets of Idaho Power. The Mortgage requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.
On February 17, 2010, Idaho Power entered into the Forty-fifth Supplemental Indenture, dated as of February 1, 2010, to the Mortgage for the purpose of increasing the maximum amount of first mortgage bonds issuable by Idaho Power from $1.5 to $2.0 billion. The amount issuable is also restricted by property, earnings, and other provisions of the Mortgage and supplemental indentures to the Mortgage. Idaho Power may amend the Mortgage and increase this amount without consent of the holders of the first mortgage bonds. The Mortgage requires that Idaho Power’s net earnings be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of
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refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.
5. NOTES PAYABLE:
IDACORP has a $100 million credit facility and Idaho Power has a $300 million credit facility, both of which expire on April 25, 2012. Commercial paper may be issued up to the amounts supported by the credit facilities. Under these facilities the companies pay a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody’s Investors Service and Standard & Poor’s Ratings Services. At December 31, 2010, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.
At December 31, 2010, no loans were outstanding on IDACORP’s or Idaho Power’s facilities. Balances and interest rates of IDACORP’s short-term and commercial paper borrowings were as follows at December 31 (in thousands of dollars):
6. COMMON STOCK:
IDACORP Common Stock
The following table summarizes common stock transactions during the last three years and shares reserved at December 31, 2010:
IDACORP enters into sales agency agreements as a means of selling its common stock from time to time. Under these agreements IDACORP sold 973,585 shares in 2010 at an average price of $35.47. In 2009, IDACORP sold 489,360 shares at an average price of $28.79 per share. In 2008, IDACORP sold 1,453,967 shares at an average price of $28.72. IDACORP’s current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2010, there were approximately 1.2 million shares remaining on the current sales agency agreement.
Idaho Power Common Stock
In 2010, 2009, and 2008, IDACORP contributed $50 million, $20 million, and $37 million respectively, of additional equity to Idaho Power. No additional shares of Idaho Power common stock were issued.
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Dividend Restrictions
A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter.
Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct. At December 31, 2010, the leverage ratios for IDACORP and Idaho Power were 52 percent and 53 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $628 million and $538 million, respectively, at December 31, 2010. There are additional covenants, subject to exceptions, that prohibit or restrict certain investments or acquisitions, mergers, or sale or disposition of property without consent; the creation of certain liens; and any agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.
Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding.
Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
7. STOCK-BASED COMPENSATION:
IDACORP has three share-based compensation plans. IDACORP’s employee plans are the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder objectives related to IDACORP’s long-term growth. IDACORP also has one non-employee plan, the Non-Employee Directors Stock Compensation Plan (DSP). The purpose of the DSP is to increase directors’ stock ownership through stock-based compensation. The DSP was terminated for purposes of new awards effective February 26, 2010, and grants to nonemployee directors subsequent to that date have been made pursuant to the LTICP.
The LTICP (for officers, key employees, and directors) permits the grant of nonqualified stock options, restricted stock, performance shares, and several other types of stock-based awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At December 31, 2010, the maximum number of shares available under the LTICP and RSP were 1,537,639 and 16,064, respectively.
Stock Awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights. Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the market price of common stock on the grant date and is charged to compensation expense over the vesting period, based on the number of shares expected to vest.
Performance-based restricted stock awards have three-year vesting periods and entitle the recipients to voting rights. Unvested shares are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to meeting specific performance conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to 150 percent of the target award. Dividends are accrued and paid out only on shares that eventually vest.
The performance awards are based on two metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.
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A summary of restricted stock and performance share activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:
The total fair value of shares vested during the years ended December 31, 2010, 2009, and 2008 was $3.3 million, $3.9 million, and $0.8 million, respectively. At December 31, 2010, IDACORP had $3.4 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. Idaho Power’s share of this amount was $3.2 million. These costs are expected to be recognized over a weighted-average period of 1.65 years. IDACORP uses original issue and/or treasury shares for these awards.
In 2010, a total of 14,982 shares were awarded to directors at a grant date fair value of $33.03 per share. Directors elected to defer receipt of 8,172 of these shares, which are being held as deferred stock units with dividend equivalents reinvested in additional stock units.
Stock Options: No stock options have been granted since 2006. The remaining unexercised stock option awards were granted with exercise prices equal to the market value of the stock on the date of grant, with a term of 10 years from the grant date and a five-year vesting period. The fair value of each option was amortized into compensation expense using graded vesting, and, as of December 31, 2010, all compensation costs related to stock options has been recognized. IDACORP uses original issue and/or treasury shares to satisfy exercised options. The following table presents information about options vested and exercised (in thousands of dollars):
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IDACORP’s and Idaho Power’s stock option transactions are summarized below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:
Compensation Expense: The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):
No equity compensation costs have been capitalized.
8. EARNINGS PER SHARE:
The following table presents the computation of IDACORP’s basic and diluted earnings per common share (EPS) (in thousands, except for per share amounts):
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The diluted EPS computation excluded 332,182 options in 2010, 594,107 options in 2009, and 556,518 options in 2008 because the options’ exercise prices were greater than the average market price of the common stock during those years. In total, 385,785 options were outstanding at December 31, 2010, with expiration dates between 2011 and 2015.
9. COMMITMENTS:
Purchase Obligations
At December 31, 2010, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights, and fuel:
As of December 31, 2010, Idaho Power had signed agreements to purchase energy from 126 CSPP facilities with contracts ranging from one to 35 years. Ninety-one of these facilities, with a combined nameplate capacity of 491 MW, were on-line at the end of 2010; the other 35 facilities under contract, with a combined nameplate capacity of 697 MW, are projected to come on-line by year end 2014. The majority of the new facilities will be wind resources which will generate on an intermittent basis. During 2010, Idaho Power purchased 910,429 megawatt-hours (MWh) from these projects at a cost of $55 million, resulting in a blended price of $60.38 per MWh. Idaho Power purchased 970,419 MWh at a cost of $59 million in 2009, and 756,014 MWh at a cost of $45.9 million in 2008.
In addition, IDACORP has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry related fees.
IDACORP’s expense for operating leases was approximately $3.4 million in 2010, $3.5 million in 2009, and $3 million in 2008.
Guarantees
Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. BCC continually assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales. In 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.
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IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of December 31, 2010, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective consolidated balance sheets with respect to these indemnification obligations.
10. CONTINGENCIES:
Legal Proceedings
Western Energy Proceedings at the FERC:
In this report, the term “western energy situation” is used to refer to the California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices, and blackouts in the western United States. High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. Some of these proceedings (referred to in this report as the western energy proceedings) remain pending before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).
There are more than 200 petitions pending in the Ninth Circuit for review of numerous FERC orders regarding the western energy situation. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power or IE are parties. Idaho Power and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters. Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained that are described below under “California Refund” and “Market Manipulation” will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.
California Refund: This proceeding originated with an effort by agencies of the State of California and investor-owned utilities in California to obtain refunds for a portion of the spot market sales from sellers of electricity into California markets from October 2, 2000, through June 20, 2001. The FERC has issued numerous orders establishing price mitigation plans for sales in the California wholesale electricity market, including the methodology for determining refunds. IE and numerous other parties have petitioned the Ninth Circuit for review of the FERC’s orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed before the Ninth Circuit, which from time to time has identified discrete cases that can proceed to briefing and decision while it stayed action on the other consolidated cases.
On May 22, 2006, the FERC approved an Offer of Settlement between and among IE and Idaho Power, the California Parties (consisting of Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources (CDWR), and the California Attorney General) and additional parties that elected to be bound by the settlement. The settlement disposed of matters encompassed by the California refund proceeding, as well as market manipulation claims and investigations relating to the western energy situation among and between the parties agreeing to be bound by it. Although many market participants agreed to be bound by the settlement, other market participants, representing a small minority of potential refund claims, initially elected not to be bound by the settlement. From time to time, as the California Parties have reached settlements with those other market participants, they have elected to opt into the IE-Idaho Power-California Parties’ settlement. The settlement provided for approximately $23.7 million of IE’s and Idaho Power’s estimated $36 million rights to accounts receivable
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from the California Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) to be assigned to an escrow account for refunds and for an additional $1.5 million of accounts receivable to be retained by the CalPX until the conclusion of the litigation. The additional $1.5 million of accounts receivable retained by the CalPX is available to fund the claims of non-settling parties if they prevail in the remaining litigation of the California refund proceeding and the balance in the escrow account is insufficient, after distribution to settling parties, to satisfy the claims of the litigants. Any additional amounts owed to non-settling parties would be funded by other amounts owed to IE and Idaho Power by the Cal ISO and CalPX, or directly by IE and Idaho Power, and any excess funds remaining in the escrow and the amounts retained by the CalPX at the end of the case would be returned to IE and Idaho Power. The remaining IE and Idaho Power receivables were paid to IE and Idaho Power under the settlement.
In an August 2006 decision, the Ninth Circuit ruled that all transactions that occurred within the CalPX and the Cal ISO markets from October 2, 2000 to June 21, 2001 were proper subjects of the refund proceeding. In that decision the Ninth Circuit refused to expand the proceedings into the bilateral market, required the FERC to consider claims that some market participants had violated governing tariff obligations at an earlier date than the refund effective date, and expanded the scope of the refund proceeding to include transactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange transactions. Parts of the decision exposed sellers to increased claims for potential refunds. The Ninth Circuit issued its mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.
On November 19, 2009, the FERC issued an order to implement the Ninth Circuit’s remand. The remand order established a trial-type hearing in which participants will be permitted to submit information regarding (i) specified tariff violations committed by any public utility seller from January 1, 2000 to October 2, 2000 resulting in a transaction that set a market clearing price for the trading period when the violation occurred, and (ii) claims for refunds for multi-day transactions and energy exchange transactions entered into during the refund period (October 2, 2000 to June 21, 2001). Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC’s order and responses to these motions. In response to a solicitation from the FERC, on September 22, 2010, IE and Idaho Power, along with a number of other parties, submitted comments to the FERC regarding the scope of the proceedings. Although IE and Idaho Power are unable to predict when or how the FERC will rule on these motions and the later comments, the effect of the remand order for IE and Idaho Power is confined to the minority of market participants that are not bound by the IE-Idaho Power-California Parties’ settlement described above. IE and Idaho Power believe the remanded proceedings will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.
In 2005, the FERC established a framework for sellers wanting to demonstrate that the generally applicable FERC refund methodology interfered with the recovery of costs. IE and Idaho Power made such a cost filing, which was rejected by the FERC. On June 18, 2009, FERC issued an order stating that it was not ruling on IE’s and Idaho Power’s request for rehearing of the cost filing rejection because their request had been withdrawn in connection with the IE-Idaho Power-California Parties’ settlement. On July 8, 2009, IE and Idaho Power sought further rehearing at the FERC because their withdrawal pertained only to the parties with whom IE and Idaho Power had settled. On June 18, 2009, in a separate order, the FERC ruled that only net refund recipients were responsible for the costs associated with cost filings. While most net refund recipients are bound by the settlement, until the Cal ISO completes its refund calculations it is uncertain whether there are any net refund recipients who are not bound by the settlement. If there are no such parties, then IE’s and Idaho Power’s request for rehearing will be moot. On May 18, 2010, the FERC denied rehearing. On June 25, 2010, IE and Idaho Power filed a petition for review of the pertinent FERC orders in the Ninth Circuit. Until the Cal ISO completes its refund calculations, it is uncertain whether there are any parties who are not bound by the California refund settlement that might be affected by the cost filing and the review of its rejection. IE and Idaho Power are unable to predict how or when the Cal ISO’s refund calculations will be completed and how or when the Ninth Circuit might rule, but the direct effect of any such calculations and ruling is confined to obligations of IE and Idaho Power to the small minority of claims of market participants that are not bound by the settlement. Accordingly, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.
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Market Manipulation: On June 25, 2003, the FERC ordered approximately 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including Idaho Power, to show cause why certain trading practices did not constitute gaming or other forms of proscribed market behavior in concert with another party (partnership) in violation of the Cal ISO and CalPX Tariffs. In 2004, the FERC dismissed the partnership show cause proceeding against Idaho Power. Later in 2004, the FERC approved a settlement of the gaming proceeding without finding of wrongdoing by Idaho Power.
The orders establishing the scope of the show cause proceedings are the subject of review petitions in the Ninth Circuit. Between August and late November 2010, at the request of IE and Idaho Power, all 12 parties that filed petitions for review of the FERC’s orders establishing the scope of the show cause proceedings filed to withdraw their petitions solely as they relate to IE and Idaho Power. The Ninth Circuit granted all the motions to withdraw during September through December 2010, dismissing with prejudice these review proceedings as they pertain to IE and Idaho Power.
On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000 through October 1, 2000, but the FERC terminated its investigations as to Idaho Power on May 12, 2004. California government agencies and California investor-owned utilities appealed the FERC’s termination of this investigation as to Idaho Power and more than 30 other market participants. On August 12, 2010, in response to a request by IE and Idaho Power, the California government agencies and California investor-owned utilities filed a request to withdraw their petitions for review solely as they relate to IE and Idaho Power. The Ninth Circuit granted the motion in September 2010 dismissing these review proceedings with prejudice as they pertain to IE and Idaho Power.
Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding separate from the California refund proceeding to determine 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, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market. In 2003, the FERC terminated the proceeding and declined to order refunds, but in 2007 the Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to require refunds. The Ninth Circuit’s opinion instructed the FERC to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and directed the FERC to include sales originating in the Pacific Northwest to the CDWR in the scope of proceeding. The Ninth Circuit officially returned the case to the FERC on April 16, 2009. On September 4, 2009, IE and Idaho Power joined with a number of other parties in a joint petition for a writ of certiorari to the U.S. Supreme Court, which was denied on January 11, 2010.
In several separate filings, the California Parties - which no longer include the California Electricity Oversight Board - and the City of Tacoma, Washington (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the case in different ways to enable them to pursue claims, as asserted by the California Parties, that all spot market sales in the Cal ISO and CalPX markets and sales to CDWR made in the Pacific Northwest, and, as asserted by Tacoma and Port of Seattle, other sales in the Pacific Northwest, from January 1, 2000 through June 20, 2001, should be subject to refund and repriced, because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. On May 22, 2009, the California Parties filed a motion with the FERC to sever claims regarding sales originating in the Pacific Northwest to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claims regarding these sales with ongoing proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint). IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties. Many other parties also filed responses to the motion of the California Parties. Tacoma and the Port of Seattle jointly filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint, and the Pacific Northwest refund remand proceeding. The Tacoma and the Port of Seattle motion asks the FERC to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20,
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2001). IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and the Port of Seattle. On April 19, 2010, the California Parties filed a motion with the FERC renewing the requests contained in their May 22, 2009 motion and on May 3, 2010, IE and Idaho Power joined with a number of other parties opposing the renewal request. On July 21, 2010, the Port of Seattle and Tacoma once again filed a motion requesting that the FERC either summarily dispose of the case or set it for hearing, and the California Parties, answering a pleading in the Brown Complaint, renewed their request for consolidation. The FERC has not acted on the Ninth Circuit remand or the motions.
IE and Idaho Power intend to vigorously defend their positions in these proceedings but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations, or cash flows.
Sierra Club Lawsuit and EPA Notice of Violation - Boardman:
In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit and Clean Air Act (CAA) violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint sought, in addition to injunctive remedies, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent of the plant and is the operator of the plant.
In September 2010, the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE has violated the New Source Performance Standards (NSPS) and operating permit requirements under the CAA, as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations.
Idaho Power continues to monitor the status of these matters but is unable to predict their outcome or what effect these matters may have on its consolidated financial position, results of operations, or cash flows.
Water Rights - Snake River Basin Adjudication:
Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the states of Idaho and Oregon. Idaho Power’s water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses.
Over time increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In the late 1970’s and early 1980’s these reduced flows resulted in a conflict between the exercise of Idaho Power’s water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power’s hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power’s project licenses, nor the Federal Power Act. The FERC entered an order implementing the legislation on March 25, 1988.
The Swan Falls Agreement provided that the resolution and recognition of Idaho Power’s water rights together with the State Water Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order
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issued by the SRBA court that same year, all claimants to water rights within the basin were required to file water right claims in the SRBA. Idaho Power has filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the effect of the Swan Falls Agreement on Idaho Power’s water right claims, including the nature and extent of the subordination of Idaho Power’s rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho’s water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho’s water resources. Idaho Power continues to work with the State of Idaho and other interested parties on these issues.
One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in 2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that committee. In January 2009, the Idaho Water Resources Board, based on the committee’s recommendations, adopted a Comprehensive Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a member of the CAMP Implementation Committee, and is currently working with the Board, other stakeholders, and the Legislature in implementing the provisions of the CAMP management plan.
Idaho Power also continues its active participation in the SRBA in seeking to ensure that its water rights are protected and that the operation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, Idaho Power does not currently anticipate any materially adverse modification of its water rights as a result of the SRBA process.
U.S. Bureau of Reclamation Proceedings:
Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation (USBR). The complaint relates to a 1923 spaceholder contract right for storage and delivery of water to Idaho Power from American Falls Reservoir, a USBR storage reservoir on the Snake River. In the complaint, Idaho Power alleges that the USBR breached the contract by the failure to recognize certain secondary storage rights referenced in the contract and claims damages for the lost generation resulting from the reduced flows downstream of the Reservoir, and asks for a prospective declaration of the rights and obligations of the parties under the 1923 contract. The USBR claims that the 1923 contract was abrogated or amended by the 1976 rebuild of American Falls Reservoir and that the secondary storage provisions of the 1923 contract no longer apply. The water rights for, and the operation of, American Falls Reservoir are also the subject of litigation in the SRBA, described above. Idaho Power has been working with the USBR and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve the contested contract issues that are common to both the SRBA and the pending federal case with the USBR. These efforts are focused on a recognition in state policy and the Idaho water plan that will promote more efficient operation of the upper Snake River reservoir system to optimize the use of Snake River flows for hydroelectric generation downstream while recognizing and protecting in-reservoir spaceholder contract rights. In an effort to promote judicial efficiency, the parties agreed to stay the pending federal case and present certain legal issues associated with the 1923 contract to the court in the SRBA case, the resolution of which are expected to resolve issues in the pending federal case. These issues were presented to the SRBA court through motions for summary judgment, which were argued in December 2010. However, as the parties continue to pursue a negotiated resolution to the 1923 contract issues, they have requested that the SRBA withhold any ruling on the motions pending the outcome of ongoing settlement negotiations. Idaho Power is unable to predict the outcome of this matter or what effect it may have on its financial position, results of operations, or cash flows.
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Oregon Trail Heights Fire:
On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho. It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes, and damage or alleged fire-related losses to approximately 30 others. Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power’s distribution poles and that high winds contributed to the fire and its resultant damage. Idaho Power received notices of claims from a number of the homeowners and their insurers and has reached settlements with most of the individuals or their insurers who have alleged damages resulting from the fire. Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations, or cash flows.
Other Legal Proceedings:
IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above. Resolution of any of these matters will take time and the companies cannot predict the outcome of any of these proceedings. The companies currently believe that resolution of these matters will not have a material adverse effect on IDACORP’s or Idaho Power’s consolidated financial positions, results of operations, or cash flows.
11. BENEFIT PLANS:
Pension Plans
Idaho Power 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. Idaho Power’s policy is to fund, with an independent corporate trustee, at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. In September 2010, Idaho Power contributed $60 million to its defined benefit pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan year. Idaho Power elected to contribute more than the minimum requirement in order to bring the plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums. Idaho Power was not required to contribute to the plan in 2009 or 2008. The market-related value of assets for the plan is equal to the fair value of the assets. Fair value is determined by utilizing publicly quoted market values and independent pricing services depending on the nature of the asset, as reported by the trustee/custodian of the plan.
In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP). At December 31, 2010 and 2009, approximately $46.2 million and $40.3 million, respectively, of life insurance policies and investments in marketable securities, all of which are held by a trustee, were designated to satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status.
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The following table summarizes the changes in benefit obligations and plan assets of these plans:
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The following table shows the components of net periodic benefit cost for these plans:
In 2011, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $10.6 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2010, relating to the pension and SMSP plans. This amount consists of $8.4 million of amortization of net loss and $0.7 million of amortization of prior service cost for the pension plan, and $1.3 million of amortization of net loss and $0.2 million of amortization of prior service cost for the SMSP.
The following table summarizes the expected future benefit payments of these plans:
Pension Protection Act: In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, companies are required to meet minimum funding levels in order to avoid benefit restrictions. The WRERA also provides for asset smoothing, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of the funding requirements. IDACORP and Idaho Power have elected to use asset smoothing.
On March 31, 2009, the U.S. Department of the Treasury (Treasury) provided guidance on the selection of the corporate bond yield curve for determining plan liabilities and allows companies to choose from a range of months in selecting a yield curve, rather than requiring the use of prescribed rates. The Treasury’s announcement specifically referenced 2009, but also indicated that technical guidance will be forthcoming to address future years. The revisions in the PPA, WRERA, Treasury guidance, and IRS guidance resulted in IDACORP and Idaho Power revising the funded status as of January 1, 2009, effectively reducing or delaying the required contributions from IDACORP and Idaho Power from what would otherwise be required, and what was previously disclosed. At January 1, 2009, Idaho Power’s pension plan was above the minimum required funding levels as revised by the PPA, WRERA, Treasury guidance and IRS guidance, but below the minimum required funding levels at January 1, 2010, and is projected to stay below the minimum
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required funding levels through 2015. As Idaho Power’s pension plan was below the minimum required funding levels at January 1, 2010, future minimum contributions are required. Based on the provisions and methodologies allowed under the PPA, WRERA, Treasury guidance, and IRS guidance, IDACORP and Idaho Power were not required to contribute to their pension plan in 2009. Unless IDACORP and Idaho Power elect an alternative amortization schedule under the new legislation discussed below, minimum required contributions to the defined benefit pension plan are estimated to be approximately $3 million in 2011, $46 million in 2012, $36 million in 2013, $32 million in 2014, and $31 million in 2015. IDACORP and Idaho Power may elect to make contributions earlier than the required dates.
The IRS and Treasury have issued final regulations effective October 15, 2009 that apply to plan years beginning on or after January 1, 2010. These regulations reflect provisions added by the PPA, as amended by the WRERA. These regulations affect sponsors, administrators, participants, and beneficiaries of single employer defined benefit pension plans. The regulations provide guidance regarding the determination of the value of plan assets and benefit liabilities for purposes of the funding requirements, regarding the use of certain funding balances maintained for those plans, and regarding benefit restrictions for certain underfunded defined benefit pension plans. These final regulations did not materially change existing estimates relating to pension plan contributions.
In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011, either (i) amortizing the funding shortfall for the applicable years over 15 years or (ii) paying interest only on the applicable plan years’ funding shortfall for two plan years followed by amortization of the actual shortfall for 7 years. If an alternate funding option is elected for plan year 2011, the only remaining plan year for which the company could make an election, it would reduce near-term required contributions to the plan by spreading them over a longer time period. The legislation does not eliminate Idaho Power’s obligation to fully fund the pension plan. In addition, the legislation outlines penalties in the form of increased pension contributions from an employer that elects one of the funding relief options at the same time that employer (or entities within its ERISA-controlled group) awards “excess employee compensation” (generally compensation over $1 million per year paid to an employee), grants “excessive” dividends, or effects specified stock redemptions. Idaho Power will evaluate the legislation and its alternatives further prior to electing an alternative, if any. See Note 3 for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.
Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact funding requirements. IDACORP and Idaho Power continue to monitor the legislative and regulatory environments for additional changes, evaluating them for their potential impact on funding requirements and strategies.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit 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 as well as their spouses and qualifying dependents. Retirees hired on or after January 1, 1999 have access to the standard medical option at full cost, with no contribution by Idaho Power. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which will limit the growth of Idaho Power’s future obligations under this plan.
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The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):
Amounts recognized in accumulated other comprehensive income consist of (in thousands of dollars):
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
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In 2011, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $2.3 million from amortizing amounts recorded in accumulated other comprehensive income as of December 31, 2010 relating to the postretirement benefit plan. This amount consists of ($0.4) million of prior service cost, $0.7 million of net loss, and $2.0 million of transition obligation.
Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage.
The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. One provision of this legislation eliminates the deductibility of employer health care costs for retiree prescription drug expenses that are covered by federal subsidy payments equivalent to Medicare Part D. While this provision is not effective until 2013, relevant income tax accounting guidance requires recognition of the future effects of new law in the period of enactment. Due to the regulatory treatment of postretirement benefit costs, the increase in certain postretirement costs relating to the legislation is deferred as a regulatory asset. See Note 2 for the tax impacts recorded as a result of this legislation.
The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (in thousands of dollars):
The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the plan was 7.5 percent and 8.0 percent in 2010 and 2009, respectively. The assumed health care cost trend rate for 2010 is assumed to decrease gradually to 4.9 percent by 2070. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was 5 percent in both 2010 and 2009. A one percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2010 (in thousands of dollars):
Plan Assumptions:
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:
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The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:
Plan Assets:
Idaho Power’s pension plan and postretirement benefit plan assets at December 31, by asset category, are as follows:
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Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2010 for the portfolio by asset class are as follows:
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to pensioners.
The three major goals in Idaho Power’s asset allocation process are, as follows:
determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations;
match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher.
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Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement benefit plan investments using the following hierarchy:
• Level 1, which refers to securities valued using quoted prices from active markets for identical assets;
• Level 2, which refers to securities not traded on an active market but for which observable market inputs are readily available; and
• Level 3, which refers to securities valued based on significant unobservable inputs.
If the inputs used to measure the securities fall within different levels of the hierarchy, the categorization is based on the lowest level input (Level 3 being the lowest) that is significant to the fair value measurement of the security. The following table sets forth by level within the fair value hierarchy a summary of the plans’ investments measured at fair value on a recurring basis at December 31, 2010:
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The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant unobservable inputs (Level 3):
Employee Savings Plan
Idaho Power has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual contributions were $5 million in each of 2010, 2009, and 2008.
Post-employment Benefits
Idaho Power 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 Idaho Power’s disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post employment benefit amounts included in other deferred credits on IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2010 and 2009 are $4.5 million and $5.2 million, respectively.
12. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:
The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance, and accumulated provision for depreciation for the years 2010 and 2009 (in thousands of dollars):
In 2010, Idaho Power sold $19 million of transmission-related assets to PacifiCorp at book value.
Idaho Power has interests in three jointly-owned generating facilities included in the table above. Under the joint operating agreements, each participating utility is responsible for financing its share of construction, operating, and leasing costs. Idaho Power’s proportionate share of related fuel expenses as well as direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements of Income.
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These facilities, and the extent of Idaho Power’s participation, were as follows at December 31, 2010 (in thousands of dollars):
IERCo, Idaho Power’s wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power’s coal purchases from the joint venture were $76 million, $66 million, and $63 million in 2010, 2009, and 2008, respectively.
Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8 million, $9 million, and $8 million in 2010, 2009, and 2008, respectively.
See Note 1 for a discussion of the property of IDACORP’s consolidated VIE.
13. ASSET RETIREMENT OBLIGATIONS (ARO):
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a 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. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation and gains or losses. The regulatory assets recorded under this order do not earn a return on investment.
Idaho Power’s recorded AROs relate to the removal of polychlorinated biphenyls-contaminated equipment at its distribution facilities and the reclamation and removal costs at its jointly owned coal-fired generation facilities. In 2010, changes in estimates at the coal-fired generation facilities resulted in a net increase of $0.9 million in the recorded ARO.
Idaho Power also has AROs associated with its transmission system and hydroelectric facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to redesignate these removal costs as regulatory liabilities. Costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s Consolidated Balance Sheets as of December 31, 2010 and 2009, were $158 million and $155 million, respectively.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
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14. INVESTMENTS:
The following table summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):
Equity Method Investments
Idaho Power, through its subsidiary IERCo, is a 33 percent owner of BCC. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects: South Forks Joint Venture; Hazelton/Wilson Joint Venture, and Snow Mountain Hydro LLC. IFS invests in affordable housing developments. All projects are reviewed periodically for impairment. The following table presents IDACORP’s and Idaho Power’s earnings (loss) of unconsolidated equity-method investments (in thousands of dollars):
Investments in Debt and Equity Securities
Investments in debt and equity securities classified as available-for-sale securities 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. The following table summarizes investments in debt and equity securities (in thousands of dollars):
The following table summarizes sales of available-for-sale securities (in thousands of dollars):
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These investments are evaluated as of the end of each reporting period to determine whether they have experienced a decline in market value that is other-than-temporary. At December 31, 2010 and 2009, IDACORP and Idaho Power did not have any securities that were in a loss position.
15. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand. Market risk may also be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price exposures. The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.
All commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting are recorded at fair value on the balance sheet. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physical forward contracts, including renewable energy certificates, qualify for the normal purchases and normal sales exception. Because of Idaho Power’s power cost adjustment mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities.
Derivative Commodity Contracts
As of December 31, 2010, Idaho Power had the following outstanding derivative commodity forward contracts that were entered into for the purpose of economically hedging forecasted purchases and sales:
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The following table presents the fair values and locations of derivative instruments recorded in the balance sheet at December 31, 2010 and 2009 (in thousands of dollars):
The following table presents gains and losses on derivatives for the years ended December 31, 2010 and 2009 (in thousands of dollars):
Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives, which are recorded in fuel inventory on the balance sheet, were immaterial for all three years. See Note 16 for additional information concerning the determination of the fair value of Idaho Power’s assets and liabilities from price risk management activities.
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Credit Risk
At December 31, 2010, Idaho Power did not have material credit exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. The majority of Idaho Power’s contracts are under the form of the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency. Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.
Credit-Contingent Features
Certain of Idaho Power’s derivative instruments contain provisions that require Idaho Power’s unsecured debt to maintain an investment grade credit rating from Moody’s Investor Services and Standard & Poor’s Ratings Services. If Idaho Power’s unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on December 31, 2010, is $5.2 million. Idaho Power has posted $4.6 million of collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2010, Idaho Power could have been required to post $0.5 million of cash collateral to its counterparties.
16. FAIR VALUE MEASUREMENTS:
IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power have the ability to access.
Level 2: Financial assets and liabilities whose values are based on the following:
a) Quoted prices for similar assets or liabilities in active markets;
b) Quoted prices for identical or similar assets or liabilities in non-active markets;
c) Pricing models whose inputs are observable for substantially the full term of the asset or liability; and
d) Pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.
IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.
Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
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Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basis location, which are also quoted under NYMEX. Trading securities consist of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan. Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity funds with quoted prices in active markets.
The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2010 and 2009 (in thousands of dollars). IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. There were no transfers between levels for the periods presented. See Note 11 for fair value information regarding IDACORP’s and Idaho Power’s benefit plans.
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The following tables present the carrying value and estimated fair value of financial instruments that are not reported at fair value, 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, deposits, 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 and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.
17. SEGMENT INFORMATION:
IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.
IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category. This category is comprised of IFS’s investments in affordable housing developments and other real estate investments, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.
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The following table summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):
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18. OTHER INCOME AND EXPENSE:
The following table presents the components of IDACORP’s Other income and Other expense (in thousands of dollars):
19. RELATED PARTY TRANSACTIONS (Idaho Power):
IDACORP
Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services Idaho Power billed IDACORP $0.8 million, $0.9 million, and $1 million in 2010, 2009, and 2008, respectively.
Ida-West
Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectric projects located in Idaho. Idaho Power paid $8 million, $9 million, and $8 million to Ida-West in 2010, 2009, and 2008, respectively.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho
We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 23, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 subsidiary (the “Company”) as of December 31, 2010 and 2009, 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, 2010. Our audits also included the 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 the standards of the Public Company Accounting Oversight Board (United States). 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 subsidiary at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 23, 2011
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SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of 2010 and 2009 (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.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
IDACORP: The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2010, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.
Idaho Power: The Chief Executive Officer and Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2010, have concluded that Idaho Power's disclosure controls and procedures are effective as of that date.
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Internal Control over Financial Reporting
IDACORP:
Management’s Annual Report on Internal Control Over Financial Reporting
The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2010. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.
Based on its assessment, management concluded that, as of December 31, 2010, IDACORP’s internal control over financial reporting is effective based on those criteria.
IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2010 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2010.
February 23, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho
We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 23, 2011
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Idaho Power Company:
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2010. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.
Based on its assessment, management concluded that, as of December 31, 2010, Idaho Power’s internal control over financial reporting is effective based on those criteria.
Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2010, and issued a report which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2010.
February 23, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho
We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Boise, Idaho
February 23, 2011
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Changes in Internal Control Over Financial Reporting
There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended December 31, 2010, requiring disclosure that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Mine Safety and Health Matters
Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming. The Mine, comprised of the Bridger surface and underground mines, supplies the mined coal to the Jim Bridger generating plant owned in part by Idaho Power. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through IERCo’s joint venture partner. IERCo owns a one-third interest in BCC. All personnel involved in the operation and maintenance of BCC are retained and employed by the IERCo’s joint venture partner. In addition to operating the Mine, the joint venture partner is responsible for the development and implementation of a safety program for the protection of Mine personnel. The mine safety program developed for BCC includes extensive training and compliance monitoring and has been developed with the objective of eliminating workplace incidents and complying with all mining-related regulations. While Idaho Power is not involved in the day-to-day operation of the Mine, the agreement governing the relationship between the joint venture partners provides that IERCo is entitled to designate two members of the four member management committee, which under the terms of the agreement is responsible for making decisions with regard to development of the coal resources, construction of improvements, mining operations, reclamation plans, and acquisition of equipment or property.
The operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. Monetary penalties are assessed by MSHA for citations. Citations, notices, and orders can be contested and appealed. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the appeal process.
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The table below summarizes the total number of citations, notices, and orders issued and penalties assessed by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other information, for the three and twelve month periods ended December 31, 2010.
Bridger Coal Mine and
Coal Processing Facility
(surface)
(underground)
Three
Twelve
Three
Twelve
Months
Months
Months
Months
Ended
Ended
Ended
Ended
Dec. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Mine Safety Act
Section 104(a) Significant & Substantial Citations (1)
Section 104(b) Orders (2)
-
-
-
-
Section 104(d) Citations & Orders (3)
-
-
-
Section 110(b)(2)Flagrant Violations (4)
-
-
-
-
Section 107(a) Imminent Danger Orders (5)
-
-
-
2(8)
Section 104(e) Notice (6)
-
-
-
-
Total Value of Proposed MSHA Assessments (in thousands)
$
$
$
$
Legal Actions (7)
-
Number of Fatalities
-
-
-
-
(1) For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
(2)
For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
(3)
For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
(4) The term “flagrant” with respect to a violation means a reckless or repeated failure to make reasonable efforts to eliminate a known violation of mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.
(5) The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
(6)
For a pattern, or the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards.
(7)
Represents the total number of legal actions before the Federal Mine Safety and Health Review Commission, which is not exclusive to citations, notices, orders, and penalties assessed by MSHA. For the three month period ended December 31, 2010, no new legal actions were initiated.
(8)
The imminent danger order reported in the Form 10-Q for the quarter ended September 30, 2010 was settled with MSHA. The settlement was the result of MSHA vacating the imminent danger order that had been contested by BCC.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The portion of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors - Nominees for Election - Terms Expire 2014,” “Continuing Directors - Terms Expire 2013,” “Continuing Directors - Terms Expire 2012,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance - Audit Committee,” paragraph 1, and “Corporate Governance - Code of Ethics,” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 19, 2011 is hereby incorporated by reference.
Information regarding IDACORP’s executive officers required by this item appears in Item 1 of this report under “Executive Officers of the Registrants.”
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ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 19, 2011 is hereby incorporated by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers and Five Percent Shareholders” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 19, 2011 is hereby incorporated by reference.
The following table includes information as of December 31, 2010, with respect to equity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP), and the Non-Employee Directors Stock Compensation Plan (DSP).
Equity Compensation Plans Not Approved by IDACORP Shareholders:
The DSP was adopted by the Board of Directors effective May 17, 1999. The purpose of the DSP is to increase directors’ stock ownership through stock-based compensation. The DSP provides for an annual stock grant valued at $45,000. Effective January 1, 2009, directors were permitted to defer their annual stock awards, which are then held as deferred stock units with dividend equivalents reinvested in additional stock units. The DSP was terminated for purposes of new awards effective as of February 26, 2010.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The portion of IDACORP’s definitive proxy statement appearing under the captions “Related Person Transaction Disclosure” and “Corporate Governance - Director Independence” paragraphs 1 and 2 to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 19, 2011 is hereby incorporated by reference.
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ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
IDACORP:
The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 19, 2011 is hereby incorporated by reference.
Idaho Power:
The following table presents fees billed for professional services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, Deloitte Entities), for Idaho Power for the fiscal years ended December 31, 2010 and 2009.
Policy on Audit Committee Pre-Approval
Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established and periodically reviews a pre-approval policy for audit and non-audit services. For 2009 and 2010, all audit and non-audit services and all fees paid in connection with those services were pre-approved by the Audit Committee.
In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax, and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include: audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed tax, audit, and audit-related services. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee, and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel, and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.
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In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations, and whether the nature of the engagement and the related fees are consistent with the following principles:
• the independent public accounting firm cannot function in the role of management of Idaho Power; and
• the independent public accounting firm cannot audit its own work.
The pre-approval policy and separate supplements to the pre-approval policy describe the specific audit, audit related, tax, and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(1) and (2) 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.
(3) Exhibits.
The agreements filed as exhibits to this Annual Report on Form 10-K are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
* Previously filed and incorporated herein by reference
151-159
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IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
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IDACORP, Inc.
CONDENSED BALANCE SHEETS
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IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2010 Form 10-K, Part II, Item 8.
Accounting for subsidiaries
IDACORP has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends of $60,571, $59,911, and $56,868 that IDACORP subsidiaries paid to IDACORP in 2010, 2009, and 2008, respectively.
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IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
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IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
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SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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.
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SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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.
Signature
Title
Date
/s/ Gary G. Michael
Chairman of the Board
February 23, 2011
Gary G. Michael
/s/ J. LaMont Keen
(Principal Executive Officer)
February 23, 2011
J. LaMont Keen
President and Chief Executive Officer and Director
/s/ Darrel T. Anderson
(Principal Financial Officer)
February 23, 2011
Darrel T. Anderson
Executive Vice President-Administrative
Services and Chief Financial Officer
/s/ Kenneth W. Petersen
(Principal Accounting Officer)
February 23, 2011
Kenneth W. Petersen
Corporate Controller and Chief Accounting Officer
/s/ C. Stephen Allred
Director
February 23, 2011
C. Stephen Allred
/s/ Richard J. Dahl
Director
February 23, 2011
Richard J. Dahl
/s/ Judith A. Johansen
Director
February 23, 2011
Judith A. Johansen
/s/ Christine King
Director
February 23, 2011
Christine King
/s/ Jan B. Packwood
Director
February 23, 2011
Jan B. Packwood
/s/ Richard G. Reiten
Director
February 23, 2011
Richard G. Reiten
/s/ Joan H. Smith
Director
February 23, 2011
Joan H. Smith
/s/ Robert A. Tinstman
Director
February 23, 2011
Robert A. Tinstman
/s/ Thomas J. Wilford
Director
February 23, 2011
Thomas J. Wilford
EXHIBIT INDEX