ITEM 1.  BUSINESS

OVERVIEW:

IDACORP, Inc. (IDACORP) is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power Company (IPC).  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.

IPC 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.  IPC is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (Bridger Coal), which supplies coal to the Jim Bridger generating plant owned in part by IPC.

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, which wound down operations in 2003.

IDACORP’s strategy emphasizes IPC as IDACORP’s core business.  Although growth in number of customers slowed in 2008, IPC is experiencing customer growth in its service area and must be prepared to meet customers’ electricity needs in the future.  IPC must make investments in infrastructure to ensure adequate electricity supply and reliable service.  IPC’s regulatory efforts have resulted in finalizing the 2007 general rate case and receiving an order in the 2008 general rate case.  IPC continues to make efforts to speed recovery of the financial and operating costs of new facilities and system improvements.  IFS and Ida-West remain components of the corporate strategy.

On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of IDACORP Technologies, Inc. to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited, and on February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM, Inc. to American Fiber Systems, Inc.  IDACORP’s consolidated financial statements reflect the reclassification of the results of these businesses as discontinued operations for all periods presented.  Discontinued operations are discussed in more detail in Note 16 to IDACORP’s and IPC’s Consolidated Financial Statements.

At December 31, 2008, IDACORP had 2,073 full-time employees, 2,057 of which were employed by IPC.

IDACORP’s only reportable business segment is IPC, which contributed $94 million to income from continuing operations in 2008.

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IDACORP and IPC make available free of charge their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the Securities and Exchange Commission, through IDACORP’s website at www.idacorpinc.com and through a link to the IDACORP website from the IPC website at www.idahopower.com.

UTILITY OPERATIONS:

IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915.  IPC’s service territory covers approximately 24,000 square miles in southern Idaho and eastern Oregon, with an estimated population of approximately one million.  IPC holds franchises 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, 2008, IPC supplied electric energy to approximately 487,000 general business customers.

IPC is one of the nation’s few investor-owned utilities with a predominantly hydroelectric generating base.  IPC owns and operates 17 hydroelectric generation developments, two natural gas-fired plants and one diesel-powered generator and shares ownership in three coal-fired generating plants.  These generating plants and their capacities are listed in Item 2 - “Properties.”  IPC’s coal-fired plants are in Wyoming, Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah.

The primary influences on electricity sales are weather, customer growth and economic conditions.  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.

Variations in weather, customer growth and economic conditions also impact power supply costs.  Drought conditions and customer growth cause a greater reliance on more expensive thermal generation and purchased power to meet load requirements.  Favorable hydroelectric generation conditions increase production at IPC’s hydroelectric generating facilities, and reduce the need for more expensive thermal generation and purchased power.  Changes in economic conditions can also affect the price of commodities, including fuel costs, which may impact power supply costs.

IPC’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, forest products, beet sugar refining and winter recreation.  On January 26, 2009, the Idaho Public Utilities Commission (IPUC) granted authority to temporarily amend IPC’s electric service agreement with one of its largest customers for the period January 1, 2009, through June 30, 2009, to provide the customer flexibility in restructuring its operations.  This amendment is not expected to have a significant impact on IPC’s earnings.

On September 17, 2008, IPC entered into an electric service agreement with a new customer, Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility under construction in Pocatello, Idaho.  The initial term of the agreement is four years beginning June 1, 2009, with automatic annual renewal after June 1, 2013 unless either party gives 12 months prior written notice of termination.  The agreement provides for a maximum demand obligation during the initial term of 82 megawatts (MW).  After June 1, 2013, Hoku may increase or decrease its total demand to between 25 MW and 175 MW.  The agreement was submitted to the IPUC for approval in October 2008.

Regulation
IPC is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the FERC, the IPUC and the Oregon Public Utility Commission (OPUC).  IPC 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.  IPC’s retail rates are established under the jurisdiction of the state regulatory commissions (see “Rates” below).  Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions have each issued orders and rules regulating IPC’s purchase of power from cogeneration and small power production (CSPP) facilities.

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IPC is subject to the provisions of the Federal Power Act as a “public utility” and as a “licensee” as therein defined and is subject to regulation by the FERC.  The Energy Policy Act of 2005 (Energy Act) 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.  As a licensee under Part I of the FPA, IPC and its licensed hydroelectric projects are subject to conditions set forth 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.

As a public utility under Part II of the FPA, IPC 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).

The state of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state.  IPC’s Brownlee, Oxbow and Hells Canyon facilities are on the Snake River where it forms the boundary between Idaho and Oregon and occupy lands in both states.  With respect to project property located in Oregon, these facilities are subject to the Oregon Hydroelectric Act.  IPC has obtained Oregon licenses for these facilities and these licenses are not in conflict with the FPA or IPC’s FERC licenses (see Part II, Item 7 - “MD&A - REGULATORY MATTERS - Relicensing of Hydroelectric Projects”).

Rates
The rates IPC charges to its general business customers are determined by the IPUC and the OPUC.  Approximately 95 percent of IPC’s general business revenue comes from customers in Idaho.  IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers.  The PCA tracks IPC’s actual net power supply costs (fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates.  Prior to February 1, 2009, approximately 90 percent of the difference between the actual and forecasted costs was deferred with interest.  Beginning on February 1, 2009, this percentage was increased to 95 percent.

IPC also has a power cost recovery mechanism in Oregon with two components that became effective June 1, 2008.  The annual power cost update (APCU) allows IPC to recover excess net power supply costs in a more timely fashion than through the previous deferral process because it reestablishes base net power supply costs annually.  The power cost adjustment mechanism (PCAM) provides for 90 percent customer sharing of deviations in actual net power supply costs from those included in the APCU if the deviations are outside of prescribed ranges and IPC meets a return-on-equity test.

The rates IPC charges to its transmission customers are determined by the FERC.  IPC’s OATT is a formula rate, which allows for transmission rates to be revised each year based on financial and operational data IPC is required to file annually with the FERC in its Form 1.

Significant rate cases and proceedings are discussed in more detail in Part II, Item 7 - “MD&A - REGULATORY MATTERS.”

Power Supply
IPC meets its system load requirements using a combination of its own generation, mandated purchases from private developers (see “CSPP Purchases” below) and purchases from other utilities and power wholesalers.  IPC’s generating plants and capacities are listed in Item 2 - “Properties.”

IPC’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.  The previous hourly system peak of 3,193 MW was set July 13, 2007.  The all-time winter peak demand is 2,464 MW set on January 24, 2008.  The previous hourly system winter peak of 2,459 MW was set in 1998.  Including the expected impact of the Hoku electric service agreement, IPC expects total system average load to grow 2.6 percent annually over the next three years.

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Because of its reliance on hydroelectric generation, IPC’s generation operations can be significantly affected by water conditions.  The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of IPC’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall and other weather and stream flow management considerations.  During low water years, when stream flows into IPC’s hydroelectric projects are reduced, IPC’s hydroelectric generation is reduced.  This results in less generation from IPC’s resource portfolio (hydroelectric, coal-fired and gas-fired) available for off-system sales and, most likely, an increased use of purchased power to meet load requirements.  Both of these situations - a reduction in off-system sales and an increased use of more expensive purchased power - result in increased power supply costs.

The following table presents IPC’s system generation for the last three years:

Under normal stream flow conditions, IPC’s system generation mix is approximately 55 percent hydroelectric and 45 percent thermal.

Stream flow conditions improved slightly in 2008 resulting in an increase of 0.7 million MWh generated from IPC’s hydroelectric facilities as compared to 2007.  The observed stream flow data released in August 2008 by the U.S. Army Corps of Engineers, Northwest Division indicated that Brownlee reservoir inflow for April through July 2008 was 4.4 million acre-feet (maf), or 70 percent of the National Weather Service Northwest River Forecast Center (NWRFC) average, compared to 2.8 maf, or 44 percent of the NWRFC average, in 2007.

Storage in selected federal reservoirs upstream of Brownlee as of February 11, 2009, was 110 percent of average.  The stream flow forecast released on February 20, 2009, by the NWRFC predicts that Brownlee reservoir inflow for April through July 2009 will be 3.3 maf, or 53 percent of the NWRFC average.

IPC’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.  IPC’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy and NV Energy (formerly Sierra Pacific Power Company).  Such 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.  IPC is a member of the Western Electricity Coordinating Council, 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.  See “Competition - Wholesale” below.

Fuel:  IPC, through its subsidiary IERCo, owns a one-third interest in Bridger Coal, which owns the Jim Bridger mine that supplies coal to the Jim Bridger generating plant (one-third owned by IPC) in Wyoming.  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.  The Jim Bridger mine has sufficient reserves to provide coal deliveries for the term of the sales agreement.  IPC 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 allow the plant to take advantage of potentially lower-cost coal from other mines for tonnage requirements above established contract minimums.

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The Bridger Coal mine experienced difficulties in meeting its production volume and operating cost goals during early 2008.  The problems stemmed from soft floor and roof stability issues that began in late December 2007 in the underground longwall mining operation (longwall).  The impact on December 2007 production was relatively minor; however the problems persisted and January 2008 production volume was approximately 20 percent of forecast.  Bridger Coal’s overall 2008 production and cost objectives were achieved by modifying the surface mine operation plan to offset the underground mining difficulties and by purchasing additional Black Butte coal.  As of year-end 2008, the longwall was operating at normal production levels.  IPC anticipates that budgeted production from both the underground and surface operations will be achieved in 2009.
NV Energy, as operator of the North Valmy generating plant, has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant through 2011.  As a 50 percent owner of the plant, IPC is obligated to purchase one-half of the coal, ranging from 515,000 tons to 762,500 tons annually.  NV Energy also has a coal supply contract with Black Butte Coal Company’s Black Butte Mine for deliveries through 2009.  IPC is obligated to purchase one-half of the coal purchased under this agreement, ranging from 450,000 to 600,000 tons annually.

The Boardman generating plant receives coal from the Powder River Basin through annual contracts.  Portland General Electric, as operator of the Boardman plant, had an agreement with Buckskin Mining Company to supply all of Boardman’s coal requirements through 2008 and has entered into a contract with Foundation Energy Sales, Inc. to supply coal from 2009 through 2011.  As a ten percent owner of the plant, IPC is obligated to purchase ten percent of the coal purchased under these agreements, which ranged from 230,000 to 270,000 tons annually under the Buckskin agreement and ranges from 87,500 to 211,000 tons annually under the Foundation Energy Sales contract.  The Boardman partners are in the process of securing contracts for additional coal tonnage that will be needed in 2010 and 2011.

IPC owns and operates the Danskin and Bennett Mountain combustion turbines, which are supplied gas through Northwest Pipeline GP’s pipeline.  Gas is purchased as needs are identified for summer peaks or to meet system requirements.  The gas is transported under a long-term agreement with Northwest Pipeline GP for 24,523 million British thermal units (MMBtu) per day.  This agreement runs through February 28, 2022, with annual extensions at IPC’s sole discretion.  IPC also has the ability to flow a total of 73,569 MMBtu on an alternate firm basis without incurring a reservation charge on the additional amount.  IPC also has entered into an agreement with Northwest Pipeline GP for 22,000 MMBtu per day of gas transport.  Gas transmission will begin November 1, 2012 and run through November 30, 2027.  In addition to this agreement, IPC has entered into a long-term agreement with Northwest Pipeline GP for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project located in Lewis County, Washington.  As the project is developed, storage capacity will be phased into service and allocated to IPC on a monthly basis.  IPC’s current storage allotment is approximately 33 percent of its total, and its full allotment is expected to be reached by January 2011.  The firm storage contract extends through November 1, 2043, with bilateral termination rights at the end of the contract.  Storage gas will be purchased and stored with the intent of fulfilling needs as identified for summer peaks or to meet system requirements.

Water Rights:  Except as discussed below, IPC has acquired water rights under applicable state law for all waters used in its hydroelectric generating facilities.  In addition, IPC holds water rights for domestic, irrigation, commercial and other necessary purposes related to other land and facility holdings within the state.  The exercise and use of all of these water rights are subject to prior rights, and with respect to certain hydroelectric generating facilities, IPC’s water rights for power generation are subordinated to certain future upstream diversions of water for irrigation and other recognized consumptive uses.

Over time, increased irrigation development and other consumptive diversions have resulted in a reduction in the stream flows available to fulfill IPC’s water rights at certain hydroelectric generating facilities.  In reaction to these reductions, IPC initiated and continues to pursue a course of action to determine and protect its water rights.  As part of this process, IPC and the state of Idaho signed the Swan Falls agreement on October 25, 1984, which provided a level of protection for IPC’s hydropower water rights at specified plants by setting minimum stream flows and establishing an administrative process governing the future development of water rights that may affect IPC’s hydroelectric generation.  In 1987, Congress passed, and the President signed into law, House Bill 519.  This legislation permitted implementation of the Swan Falls agreement and further provided that during the remaining term of certain of IPC’s project licenses the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of IPC’s project licenses or imprudent for the purposes of determining rates under Section 205 of the FPA.  The FERC entered an order implementing the legislation on March 25, 1988.

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In addition to providing for the protection of IPC’s hydroelectric water rights, the Swan Falls agreement contemplated the initiation of a general adjudication of all water uses within the Snake River basin.  In 1987, the director of the Idaho Department of Water Resources filed a petition in state district court asking that the court adjudicate all claims to water rights, whether based on state or federal law, within the Snake River basin.  The court signed a commencement order initiating the Snake River Basin Adjudication (SRBA) on November 19, 1987.  This legal proceeding was authorized by state statute based upon a determination by the Idaho Legislature that the effective management of the waters of the Snake River basin required a comprehensive determination of the nature, extent and priority of all water uses within the basin.  The adjudication is proceeding and is expected to continue for at least the next several years.  IPC has filed claims to its water rights within the basin and is actively participating in the adjudication in an effort to ensure that its water rights and the operation of its hydroelectric facilities are not adversely impacted.  In certain instances, the adjudication of water rights in the SRBA results in the initiation of litigation, called subcases, to determine the scope and nature of a particular water right.  IPC is involved in subcases involving not only its water rights but also the water rights of other claimants.  One such subcase involves IPC’s water rights at the Swan Falls project on the Snake River and several other upstream hydroelectric projects that are the subject of the Swan Falls Agreement.  IPC also has initiated legal action against the U.S. Bureau of Reclamation (USBR) over the interpretation and effect of a 1923 contract with the USBR on the operation of the American Falls Reservoir and the release of water from that reservoir to be used at IPC’s downstream hydroelectric projects.

Please see further discussion in Part II, Item 7 - “MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Idaho Water Management Issues” and “MD&A - REGULATORY MATTERS - Relicensing of Hydroelectric Projects.”

Integrated Resource Plan (IRP):   IPC filed its 2006 Integrated Resource Plan (IRP) with the IPUC in September 2006 and with the OPUC in October 2006.  The 2006 IRP previewed IPC’s load and resource situation for the next twenty years, analyzed potential supply-side and demand-side options and identified near-term and long-term actions.

The two primary goals of the 2006 IRP were to (1) identify sufficient resources to reliably serve the growing demand for electric service within IPC’s service area throughout the 20-year planning period and (2) ensure that the portfolio of resources selected balances cost, risk and environmental concerns.

The IPUC accepted the 2006 IRP in March 2007 and the OPUC acknowledged the 2006 IRP in September 2007.  With its acceptance of the 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP with those submitted by other Idaho utilities.  To comply with this request, IPC provided an update on the status of the 2006 IRP to both the IPUC and OPUC in June 2008.  An IRP Addendum was also filed with the OPUC in February 2009 to address the need for the Boardman to Hemingway Transmission Project.  IPC is currently preparing the 2009 IRP, which is scheduled to be completed in June 2009.  Please see further discussion in Part II - Item 7 - “MD&A - REGULATORY MATTERS - Integrated Resource Plan.”

CSPP Purchases:   As mandated by PURPA and the adoption of avoided cost rates by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers.  Under these contracts, IPC is required to purchase all of the output from the facilities located inside its service territory.  For projects located outside its service territory, IPC is required to purchase the output that it has the ability to receive at the facility’s requested point of delivery on the IPC system.  The IPUC jurisdictional portion of the costs associated with CSPP contracts are fully recovered through base rates and the PCA.  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 OPUC jurisdictional portion of the costs associated with CSPP contracts is recovered through general rate case filings.  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.  The Published Avoided Cost is a price established by the IPUC and OPUC to estimate IPC’s cost of developing additional generation resources.  If a PURPA project does not qualify for Published Avoided Costs, then IPC is required to negotiate the terms, prices and conditions with the developer of that project.  These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

During 2008, at the IPUC’s direction, IPC conducted workshops to review the Published Avoided Cost model input components.  A settlement stipulation was filed with the IPUC for its consideration that, if accepted, will result in an increase in the non-fuel component of the Published Avoided Costs.

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As of December 31, 2008, IPC had signed agreements to purchase energy from 92 CSPP facilities with contracts ranging from one to 30 years.  Seventy-nine of these facilities, with a combined nameplate capacity of 267 MW, were on-line at the end of 2008; the other 13 facilities under contract, with a combined nameplate capacity of 190 MW, are projected to come on-line during 2009 and 2010.  The majority of the new facilities will be wind resources which will generate on an intermittent basis.  During 2008, IPC purchased 756,014 megawatt-hours (MWh) from these projects at a cost of $45.9 million, resulting in a blended price of 6.1 cents per kilowatt hour.

Wholesale Energy Market Activities:   Guided by a risk management policy and frequently updated operating plans, IPC participates in the wholesale energy market by buying power to help meet load demands and selling power that is in excess of load demands.  IPC’s market activities are influenced by its customer loads, market prices, and cost and availability of generating resources.  Some of IPC’s hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run 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 to vary water usage to maximize generation unit efficiency, capture marketplace economic benefits and meet load demand.  Compliance factors, such as allowable river stage elevation changes and flood control requirements, and wholesale energy market prices influence these dispatch decisions.

IPC has one firm wholesale power sales contract.  The sales contract is with the Raft River Electric Cooperative for up to 15 MW.  This contract expires in September 2009; however, Raft River Electric Cooperative has provided notice that it intends to renew the contract, as allowed in the original agreement, through September 2011.

IPC has one wholesale reserve sales contract, with United Materials of Great Falls, Inc. (United Materials).  This agreement requires IPC to carry up to 0.45 MW of reserves associated with an energy sales agreement dated January 2004 between IPC and United Materials from the Horseshoe Bend Wind Farm.  The term of this agreement began in January 2008, and runs seasonally through May 2013.

IPC has four firm wholesale purchased power contracts.  One contract is with PPL Montana, LLC, now known as PPL EnergyPlus, LLC, for 83 MW per hour during heavy load hours, to address increased demand during June, July and August.  The term of this contract began in June 2004 and runs through August 2009.  IPC entered into a second seasonal contract for 83 MW with PPL EnergyPlus, LLC that runs from June 2010 through August 2011.  In January 2008, the IPUC approved a power purchase agreement for 13 MW (nameplate generation) from the Raft River Geothermal Power Plant Unit #1 located in southern Idaho that converted a CSPP contract to a purchased power contract.  The contract term is through April 2033.  The fourth contract is with Telocaset Wind Power Partners, LLC, a subsidiary of Horizon Wind Energy, for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon.  The contract term is through December 2027.

Transmission Services
IPC provides wholesale transmission service and provides firm and non-firm wheeling services for eligible transmission customers.  IPC’s system lies between and is interconnected with the winter-peaking northern and summer-peaking southern regions of the western power system.  This geographic position allows IPC to provide transmission services and to reach a broad power market.

IPC and PacifiCorp are jointly exploring the Gateway West project to build transmission lines between Windstar, a substation located near Douglas, Wyoming and Hemingway, a substation located in the vicinity of Melba and Murphy, Idaho near Boise.  Initial phases of the project could be completed by 2014.  Remaining phases of the project could be constructed as demand requires.

Construction of a new 500-kV station named Hemingway is expected to address growth, capacity and operating constraints.  The station was originally part of the Gateway West Project but the timing of this addition was accelerated to 2010 to help meet forecast deficits and improve reliability.  As part of the Hemingway Station Project, the Hemingway-Hubbard transmission line is expected to provide power to the Treasure Valley area of southwest Idaho by 2010.  The Hemingway-Hubbard line will consist of a new 230-kV double circuit transmission line and convert an existing 138-kV transmission line to 230-kV.

The Boardman-Hemingway transmission line is expected to relieve existing congestion by increasing transmission capacity and improving reliability.  It will allow for the transfer of up to 1,500 MW of additional energy between Idaho and the Northwest.  IPC expects to seek partners for up to 50 percent of the project when construction commences.  The line has a target in-service date of June 2013.

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These projects are discussed in more detail in Part II - Item 7 - “MD&A – LIQUIDITY AND CAPITAL RESOURCES – Capital Requirements” and “MD&A - REGULATORY MATTERS - Transmission Projects.”
On March 28, 2008, Great Basin Transmission, LLC (Great Basin) exercised its option to purchase the southern portion of the Southwest Intertie Project (SWIP), which consists principally of a federal permit for a specific transmission corridor in Nevada and Idaho and private rights-of-way in Idaho.  This sale closed during the second quarter of 2008, and resulted in a net pre-tax gain of approximately $3 million.  On December 30, 2008, IPC and Great Basin reached an agreement on the sale of the northern portion of the SWIP, which is expected to close in the first quarter of 2009 and result in a pre-tax gain of $0.2 million.

Environmental Regulation
IPC’s activities are 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.  Environmental regulation continues to impact IPC’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.  IPC’s environmental compliance costs will continue to be significant for the foreseeable future.

Based upon present environmental laws and regulations, IPC estimates its 2009 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFUDC), will total $17 million.  Studies and measures related to environmental concerns at IPC’s hydroelectric facilities account for $6 million and investments in environmental equipment and facilities at the thermal plants account for $11 million.  For 2010 and 2011, environmental-related capital expenditures, excluding AFUDC, are estimated to be $74 million.  Anticipated expenses related to IPC’s hydroelectric facilities account for $44 million, and thermal plant expenses are expected to total $30 million.

IPC anticipates approximately $20 million in annual operating costs for environmental facilities during 2009.  Hydroelectric facility expenses and thermal plant expenses account for the majority of the costs at approximately $14 million and $6 million, respectively.  For 2010 and 2011, total environmental related operating costs are estimated to be approximately $57 million.  Expenses related to the hydroelectric facilities are expected to be $43 million, and thermal plant expenses are expected to be $14 million during this period.

Water:   As required under the Federal Water Pollution Control Act Amendments of 1972, IPC has received necessary environmental permits and authorizations and has prepared necessary plans relating to operations and water quality, such as effluent discharge, spill prevention and countermeasures, and storm water pollution prevention.

The FERC licenses issued for IPC’s American Falls and Cascade hydroelectric generating plants require aeration of turbine water to meet dissolved oxygen standards in the tail waters downstream from the plants.  In order to comply with the licenses, IPC installed and operates aeration equipment at both plants and submits compliance reports to the appropriate regulatory agencies.

The FERC licenses issued for IPC’s Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon, Bliss and CJ Strike hydroelectric projects require dissolved oxygen and temperature monitoring and reporting.  IPC submits compliance reports to the appropriate regulatory agencies.

The FERC license for the CJ Strike project also requires monitoring of total dissolved gas during spill periods.  IPC installs monitors during periods of spill that record gas levels in spilled water and reports the results to the appropriate regulatory agencies.

Hazardous/Toxic Wastes and Substances:   Under the Toxic Substances Control Act, the EPA has adopted regulations governing the use, storage, inspection and disposal of electrical equipment that contains polychlorinated biphenyls (PCBs).  The regulations permit the continued use and servicing of certain equipment (including transformers and capacitors) that contain PCBs.  IPC continues to meet federal requirements of the Toxic Substances Control Act for the continued use of equipment containing PCBs.  IPC continues to eliminate PCBs as part of its long-term strategy.  This program will reduce costs associated with the long-term monitoring of PCB-containing equipment, responding to spills and reporting to the EPA.  In 2008, IPC spent approximately $0.6 million identifying and eliminating PCBs.

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Air Quality Issues: IPC owns two natural gas combustion turbine power plants and co-owns three coal-fired power plants that are subject to air quality regulation.  The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho.  The coal-fired plants are:  Jim Bridger located in Wyoming; Boardman located in Oregon; and Valmy located in Nevada.

For a more detailed discussion of these and other environmental issues, including greenhouse gases, climate change and endangered species please see Part II, Item 7 – “MD&A – Legal and Environmental Issues – Environmental Issues.”

Energy Efficiency Programs
In 2008, IPC spent approximately $21.2 million to promote energy efficiency and summer peak reduction through its energy efficiency programs, which have previously been referred to as Demand Side Management programs.  Approximately $18.9 million of funding for program development, implementation and administration comes from the Idaho and Oregon tariff riders for energy efficiency.  The balance of the funding comes from IPC base rates and a small amount was previously obtained from residual funds from the BPA’s Conservation and Renewables Discount which was discontinued in 2007.

Approximately $2.4 million was spent on research, analysis and development, education, technology evaluation, and market transformation.  A portion of this activity was accomplished in conjunction with the Northwest Energy Efficiency Alliance (NEEA).  IPC contributed $0.9 million to the NEEA.

The following energy efficiency programs target savings across the entire year for a wide range of customer segments with an emphasis on reducing energy during the summer peak:

•      Approximately $4.4 million was devoted to achieving summer peak reduction through focusing on irrigation pumping and residential air conditioning equipment control measures.

•      The residential energy efficiency programs targeted new and existing homes, focusing on customer education and the application of energy efficiency remediation, including energy efficient building techniques, insulation augmentation, air duct sealing, and the use of efficient lighting.  This program’s 2008 spending was approximately $4.2 million.

•      Programs for new or existing industrial and commercial facilities focus on application of energy efficient techniques and technologies as well as operational and management processes to reduce energy consumption.  Approximately $8.1 million was spent on these programs.

•      Approximately $2.1 million was devoted to irrigation efficiency programs.  Irrigation customers can receive financial incentives for either improving the energy efficiency of an irrigation system or installing a new energy efficiency system.

In 2008, IPC’s energy efficiency programs reduced energy usage by approximately 134,000 MWh and the targeted demand reduction programs resulted in a summer peak reduction of about 54 MW.

Competition
Retail:   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.  In the past, some state regulatory authorities explored changing utility regulations in response to federal and state statutory changes, with the intent of increasing retail competition.  However, restructuring of the electric industry has stalled at both the national level and in the Pacific Northwest.

Wholesale:  The 1992 National Energy Policy Act and the FERC’s rulemaking activities have established the regulatory framework to open the wholesale energy market to competition.  This act permits entities to develop independent electric generating plants for sales to wholesale customers, and authorizes the FERC to order transmission access for third parties to transmission facilities owned by another entity.  This act does not, however, permit the FERC to require transmission access to retail customers.  Open-access transmission for wholesale customers provides energy suppliers with opportunities to sell and deliver electricity at market-based prices.  IPC actively monitors and participates, as appropriate, in energy industry developments, to maintain and enhance its ability to effectively participate in wholesale energy markets in a manner consistent with its business goals.  For more information, see Part II, Item 7 - “MD&A - REGULATORY MATTERS – Federal Regulatory Matters.”

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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 $11 million, $15 million and $19 million in 2008, 2007 and 2006, respectively.  IFS’s portfolio also includes historic rehabilitation projects such as, the Empire Building in Boise, Idaho.  IFS made $8 million of new investments during 2008 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, 2008, the gross amount of IFS’s portfolio equaled $183 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 three 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.  IPC purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $8 million each year in 2008, 2007 and 2006.