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IDAHO POWER CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
[February 20, 2014]

IDAHO POWER CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Edgar Glimpses Via Acquire Media NewsEdge) INTRODUCTION In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part 1 - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

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 508,000 general business customers as of December 31, 2013. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the Federal Energy Regulatory Commission (FERC). The IPUC and OPUC 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. 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 open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-response programs, and to seek to earn a return on investment.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. 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, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the economy across the service territory), and the availability and price of purchased power and fuel. Idaho Power 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 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 of 1978 (PURPA); and IDACORP Energy Services Co., which is the former limited partner of, and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003. 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.

32-------------------------------------------------------------------------------- Table of Contents EXECUTIVE OVERVIEW Management's Outlook In recent years Idaho Power has seen positive growth in its customer count and associated positive impacts on Idaho Power's revenue. To encourage responsible and sustainable growth, and as part of its planning for the future, Idaho Power actively participates in and supports state and local economic development initiatives. Idaho Power's biennial Integrated Resource Plan (IRP) seeks to identify cost-effective and responsible means for Idaho Power to address customer growth. Recent infrastructure investments, such as the Langley Gulch power plant, and future anticipated infrastructure projects, including those identified in the 2013 IRP, are intended to help ensure Idaho Power continues to provide reliable service to existing customers while at the same time meeting expected future customer growth. Idaho Power has also invested significant capital in recent years to maintain and replace aging assets and to build for the future. Idaho Power expects to continue these significant levels of capital investment going forward. Idaho Power's substantial capital projects include upgrades to generation plants, a multi-year plan for replacements of underground conductor, and ongoing system upgrades, as well as continued progress on the Boardman-to-Hemingway and Gateway West 500-kV transmission lines. As of the date of this report, Idaho Power estimates capital expenditures of $1.47 billion to $1.56 billion from 2014 through 2018.

In tandem with this growth, Idaho Power operates within what it believes to be a constructive regulatory framework, achieved through general rate cases, subject-specific rate filings, and cost recovery mechanisms that share risks and benefits with Idaho Power customers. To further complement these efforts, Idaho Power has also been focusing on controlling operating, maintenance, and capital costs through process review and improvement initiatives, and by empowering employees to identify new means to reduce costs, increase efficiencies, and enhance individual and enterprise performance for the benefit of IDACORP's shareholders, Idaho Power's customers, and both companies' other stakeholders.

Another area of recent focus has been IDACORP's dividend. In November 2011, IDACORP's board of directors adopted a target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings. During 2012, IDACORP's quarterly dividend was increased from $0.30 to $0.38 per share, and in September 2013 the quarterly dividend was increased again, to $0.43 per share. Idaho Power's need and ability to construct infrastructure, the availability of timely regulatory recovery of costs associated with that construction, and IDACORP's earnings, among other factors discussed elsewhere in this report, all influence dividend decisions. A number of recent positive outcomes in those areas, such as the completion of the Langley Gulch power plant in June 2012 and inclusion of associated costs in rates, combined with the corresponding impact on IDACORP's financial performance, have been important elements that IDACORP's board of directors has considered in its recent dividend decisions. IDACORP anticipates the potential for further growth in the dividend as the company and board of directors weigh factors governing dividend decisions and continues to work toward its target dividend payout ratio.

Brief Overview of 2013 Results IDACORP's 2013 earnings per diluted share of $3.64 were $0.18 above its 2012 earnings per diluted share of $3.46 and reflect the impacts of a full year of Langley Gulch-related rate increases that went into effect during mid-2012, combined with increased weather-related sales across all customer classes.

IDACORP's 2013 and 2012 results also reflect the retrospective adoption of Accounting Standards Update No. 2014-01, which increased earnings per share by $0.10 and $0.09, respectively, as compared to what would have been reported under the previous method of accounting. See Note 1 to the consolidated financial statements included in this report for a further description of the nature and impact of this adoption. Idaho Power's 2013 return on year-end equity in the Idaho jurisdiction again exceeded 10.0 percent, triggering the sharing mechanism in Idaho Power's December 2011 IPUC settlement agreement discussed below. Triggering of the sharing mechanism resulted in a $24.1 million reduction to operating income for 2013, reflecting earnings to be shared with Idaho customers to reduce future rates. A more specific discussion of the factors influencing IDACORP's and Idaho Power's results for 2013, including a quantification of their respective impacts, is included below in this MD&A.

33-------------------------------------------------------------------------------- Table of Contents 2013 Accomplishments and 2014 Initiatives IDACORP's business strategy emphasizes Idaho Power as IDACORP's core business.

For the past several years, Idaho Power has been implementing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. This strategy is described in Part I, Item 1 - "Business" of this report. Examples of IDACORP's and Idaho Power's achievements during 2013 under its three-part business strategy include: • earnings growth for a sixth consecutive year; • execution of business optimization initiatives, resulting in operations and maintenance costs in 2013 that are largely consistent with costs in 2012; • reduced employee count through planned retirements, natural attrition, and business optimization; • transition to a new customer information and billing system, which is the final component of Idaho Power's Smart Grid project; • continued progress toward the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects; • achievement of Idaho Power's original goal, announced in 2009, to reduce CO2 emissions by 10 to 15 percent below 2005 emissions for the four-year period 2010 through 2013; • continued progress toward achieving IDACORP's previously adopted dividend policy, by increasing the quarterly dividend 13.2 percent from $0.38 per share to $0.43 per share during 2013; and • Idaho Power's ranking improved from 39 to 29 in the annual "40 Best Energy Companies" list published by Public Utilities Fortnightly, and Idaho Power was one of nine energy companies out of 150 evaluated to be named as a "sustainable utility leader" by Target Rock Advisors.

For 2014, in addition to its specific projects, Idaho Power has established a number of organizational initiatives, including the following: • emphasize and enhance its enterprise safety culture; • actively manage its costs and ability to fund planned capital investments by seeking to better optimize business practices, and maintain or improve capital liquidity and credit ratings; • continue to emphasize innovative approaches to regulatory strategy; • promote economic development through collaboration with the states of Idaho and Oregon to attract new businesses that fit Idaho Power's resource and load profile mix; • focus on operational excellence through responsible resource planning, by matching resources to customer loads, managing the impacts of environmental regulations, maintaining Idaho Power's hydroelectric base, and enhancing power quality and reliability and customer satisfaction; • continued progress toward federal relicensing for the Hells Canyon Complex (HCC) hydroelectric facility; • continued progress toward achieving the extended CO2 intensity reduction goal of 10 to 15 percent below 2005 CO2 emission intensity, for the period from 2010 through 2015; and • address workforce attrition associated with anticipated retirements, with targeted succession planning and training programs.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, operational, weather-related, economic, and other factors, many of which are described below.

Timely Regulatory Cost Recovery: The price that Idaho Power is authorized to charge for its electric service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions, and in furtherance of its goal of advancing a purposeful regulatory strategy, Idaho Power has focused on timely recovery of its costs through filings with the company's regulators, and on the prudent management of expenses and investments. Effective implementation of Idaho Power's regulatory strategy is particularly important in an economic climate that continues to put pressure on regulators to limit rate increases or take other actions to mitigate the impact of rate increases on customers. The number of regulatory filings from 2010 through 2013 exceeded historical averages. Idaho Power will be evaluating its regulatory strategy and options during 2014, and if deemed appropriate could file an application for a general rate change or for extension of the terms of the existing December 2011 regulatory settlement described below. During February 2014, Idaho Power held preliminary discussions with the IPUC Staff regarding such an extension.

34-------------------------------------------------------------------------------- Table of Contents The most significant rate proceedings during 2012 and 2013 that have impacted revenues are listed below. Additional important regulatory matters are also discussed in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Proceeding Description Status Langley Gulch Request for recovery of and IPUC approved a $58.1 million Power Plant return on Idaho Power's increase in rates, effective investment in the Langley July 1, 2012; OPUC approved a Gulch power plant, including $3.0 million increase in rates operating costs effective October 1, 2012 Idaho Jurisdiction Annual Idaho-jurisdiction PCA IPUC approved a $43.0 million Power Cost mechanism rate change increase in PCA rates, effective Adjustment (PCA) - for the period from June 1, 2012 2012 to May 31, 2013 2011 Revenue Rate adjustment pursuant to IPUC approved using $27.1 Sharing January 2010 settlement million of sharing to reduce PCA agreement rates.

Idaho Jurisdiction Annual Idaho-jurisdiction PCA IPUC approved a $121.3 million PCA - 2013 mechanism rate change net increase in PCA rates, effective for the period from June 1, 2013 to May 31, 2014 2012 Revenue Rate adjustment pursuant to IPUC approved using $7.2 million Sharing December 2011 settlement of sharing against PCA rates, agreement effective for the period from June 1, 2013 to May 31, 2014 Depreciation for Application for removal from IPUC approved a $10.6 million Non-AMI Meters rates of accelerated decrease in rates and associated depreciation expense depreciation expense, effective associated with non-advanced June 1, 2012 metering infrastructure (AMI) metering equipment In December 2011, the IPUC approved a settlement stipulation that permits Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho-jurisdiction return on year-end equity (Idaho ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The settlement stipulation also provides for the sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. Based on its Idaho ROE, in 2012 and 2013 Idaho Power recorded $21.8 million and $24.1 million provisions for sharing with customers, respectively, pursuant to the terms of the December 2011 settlement stipulation.

Idaho Power did not amortize any additional ADITCs in those years. The specific terms of the settlement stipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC under the settlement stipulation provides an element of earnings stability for 2014.

Idaho Power seeks to take an active approach to regulatory matters. For example, in November 2013 Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million in the normalized or "base level" power supply expense to be used in the determination of the PCA rate that will become effective June 1, 2014. While approval of the application would result in no net change in the amount collected through base rates and the PCA mechanism in the aggregate, approval of the application would decrease the amount of any base rate increase requested in Idaho Power's next general rate case application filed with the IPUC.

Economic Conditions and Customer/Load Growth: Idaho Power monitors a number of economic indicators, including employment statistics, growth in customer numbers, foreclosure rates, and other housing-related data on a national and state scale and within Idaho Power's service territory. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and the need to construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. Idaho Power has observed what it believes to be a number of improvements in economic conditions in its service territory during 2012 and 2013. For example: • Based on Idaho Department of Labor preliminary data, the total number of persons employed in the service area in December 2013 was 451,526, eclipsing the previous peak established in December 2006, and the associated unemployment rate for the service area was 5.3 percent, compared to the State of Idaho rate of 5.7 percent. The U. S. rate stood at 6.7 percent, according to U.S.Department of Labor data.

• Gross area product for Idaho Power's service area, as reported by Moody's Analytics, indicates growth of 2.9 percent for 2013. Moody's forecasts 2.9 percent and 3.7 percent growth in gross area product for 2014 and 2015, respectively.

• Housing market fundamentals continue to improve when measured by foreclosure rates, market prices, new housing permits, and available supply of housing. Residential customer growth for 2013 was 1.5 percent.

35 -------------------------------------------------------------------------------- Table of Contents • A number of businesses have recently constructed, or are in the process of constructing, sizable facilities in Idaho Power's service territory, including office and manufacturing complexes, particularly in the food processing industry.

Based on recent economic data, Idaho Power predicts that customer growth within its service area will continue to be positive. Idaho Power's most recent load forecast predicts a 1.4 percent five-year compound annual growth rate in residential loads and a 2.1 percent five-year compound annual growth rate in residential customers. For resource planning purposes, Idaho Power's 2013 IRP, filed with the IPUC and OPUC in June 2013, included a forecasted long-term annual customer growth rate more closely aligned with the 1.1 percent growth rate it experienced in 2012. Both are improvements over the 0.8 percent average annual growth rate experienced the past 5 years, but less than the 2.6 percent average annual growth realized over the past 20 years.

Should the updated estimates of higher growth rates materialize, or were there to be a significant increase in loads due to new, unanticipated large-load customers, growth would exceed the projections included in the 2013 IRP and Idaho Power could be required to adjust its infrastructure development timing and plans accordingly.

Weather Conditions and Associated Impacts: Weather and agricultural growing conditions have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy use for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. In 2013, abnormally cold temperatures in the first quarter and in December drove increased demand by retail customers for the operation of electric heating systems. Warm late-spring and summer temperatures drove higher-than-normal demand for electric power for the operation of air conditioning units and irrigation equipment.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. However, the availability and volume of hydroelectric power generated depends on several factors - the snow pack levels in the mountains upstream of Idaho Power's facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. Idaho Power's hydroelectric generation during 2013 was 5.7 million megawatt-hours (MWh), compared to actual generation of 8.0 million MWh in 2012 and 10.9 million MWh in 2011. Median annual hydroelectric generation is 8.4 million MWh. When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power - but most of the increase in power supply costs is collected from customers through the Idaho and Oregon PCA mechanisms. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the PCA mechanisms. Idaho Power's April 2013 request for a $140.4 million PCA rate increase for the 2013-2014 PCA collection period was largely the result of unfavorable hydroelectric conditions during the 2012-2013 PCA year and a forecast of below average hydroelectric generating conditions during the 2013-2014 PCA year.

When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators - increasing the available supply of lower-cost power, lowering regional wholesale market prices, and impacting the revenue Idaho Power receives from off-system sales of its excess power. Conversely, when hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would generally have less surplus energy available for sale into the wholesale markets at those times. Much of the adverse or favorable impact of this volatility is addressed through the PCA mechanisms.

Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's generation capacity, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Operation of Idaho Power's Langley Gulch power plant, placed into operation in June 2012, has increased Idaho Power's use of natural gas as a generation fuel and thus its exposure to volatility in natural gas prices.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is obligated to purchase power from some PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices.

This increases the likelihood that Idaho Power will at times be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources (such as wind 36-------------------------------------------------------------------------------- Table of Contents energy) into Idaho Power's portfolio also creates a number of complex operational challenges and risks that Idaho Power must address. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of nameplate capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases have contributed to increases in customer rates.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power, including substantially all of the Idaho-jurisdiction PURPA power purchase costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel and other hedging strategies in order to manage the risks relating to fuel and power price exposures.

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 audits by agencies and quasi-governmental agencies, including the FERC and the North American Electric Reliability Corporation.

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 or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives to help ensure compliance, and periodically evaluates and updates those policies and initiatives.

In particular, environmental laws and regulations may, among other things, increase the cost of operating generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power cease operating certain generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations by the end of 2020, the decision for which was driven in large part by the substantial cost of environmental controls. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power will continue to assess, to the extent determinable, the potential impact on the costs to operate its generation facilities, as well as the willingness of joint owners of power plants to fund any required pollution control equipment upgrades. To that end, in the first quarter of 2013 Idaho Power concluded cost studies and scenario analyses to assess the potential future investments necessary for the continued operation of the Jim Bridger and Valmy coal-fired generation facilities. Idaho Power published the results of the study in February 2013, concluding that planned investments in environmental controls at both plants are appropriate.

Other Notable Matters and Areas of Focus Pension Plan Funding: From 2011 through 2013, Idaho Power contributed $93 million to its defined benefit pension plan. Idaho Power had no minimum required contribution to its defined benefit pension plan in 2013; however, it made discretionary contributions of $30 million in 2013 to more adequately fund the plan. Idaho Power's minimum contribution requirement for 2014 is estimated at $1.4 million, though it plans to contribute at least $20 million to the pension plan during 2014.

In May 2011 the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. While the IPUC's authorization to increase the annual recovery has decreased the adverse cash flow impacts of the contributions, the magnitude of the contributions relative to the annual cost recovery can still create a lag between the timing of expenditures and their recovery.

Water Management and Relicensing of the Hells Canyon Hydroelectric Project: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, Idaho Power is involved in renewing its federal license for the HCC, its largest hydroelectric generation source, and recently received a 30-year license renewal from the FERC for its Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, federal and state regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of the HCC. However, given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial, and the terms of, and costs associated with, any resulting license are not currently determinable.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to enhance system reliability and access to wholesale markets. Its most notable transmission projects in progress are the proposed Boardman-to-Hemingway and Gateway West 500-kV transmission projects. In January 2012, Idaho Power entered into cost-sharing 37-------------------------------------------------------------------------------- Table of Contents arrangements with third parties for the permitting phases of both projects.

Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. As it relates to the Boardman-to-Hemingway project, for which Idaho Power is the project manager, environmental requirements and regulations (particularly relating to sage grouse) for the siting process have changed significantly since commencement of the project, making the identification of a suitable route for the transmission line more difficult. This has resulted in project delays and increased permitting costs. In light of the delays and siting impediments that have occurred and are expected to continue, Idaho Power estimates that the in-service date for the Boardman-to-Hemingway line would be 2020 or beyond. The Boardman-to-Hemingway line remains Idaho Power's preferred resource alternative.

Given project delays, however, Idaho Power is conducting an enhanced review of other power supply resource options as it progresses with the Boardman-to-Hemingway line.

Summary of 2013 Financial Results The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2013, 2012, and 2011. IDACORP's 2013 and 2012 results reflect the retrospective adoption of Accounting Standards Update No. 2014-01, which increased earnings by $5.1 million and $4.3 million, respectively, as compared to what would have been reported under the previous method of accounting. See Note 1 to the consolidated financial statements included in this report for a further description of the impact of this adoption.

Year Ended December 31, 2013 2012 2011 Idaho Power net income $ 176,741 $ 168,168 $ 164,750 Net income attributable to IDACORP, Inc. $ 182,417 $ 173,014 $ 169,981 Average outstanding shares - diluted (000's) 50,126 50,010 49,558 IDACORP, Inc. earnings per diluted share $ 3.64 $ 3.46 $ 3.43 The table below provides a reconciliation of net income attributable to IDACORP, Inc. for year ended December 31, 2013 to the same period in 2012 (items are in millions and are before tax unless otherwise noted): Net income attributable to IDACORP, Inc. - December 31, 2012 (as previously reported) $ 168.7 Effect of an accounting method change for IDACORP Financial Services affordable housing investment amortization 4.3 Net income attributable to IDACORP, Inc. - December 31, 2012 (as reported under new method) 173.0 Change in Idaho Power net income: Rate changes, net of changes in power supply costs and PCA mechanisms $ 30.1 Change in sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts 18.0 Increases in sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts 8.9 Other changes in operating revenues and expenses, net (2.6 ) Greater sharing-related costs reflected as pension expense and revenue sharing (2.3 ) Increase in Idaho Power operating income 52.1 Decrease in allowance for funds used during construction (AFUDC) (11.8 ) Gains on sale of investments 11.6 Changes in other non-operating income and expenses (3.0 ) Tax method changes in 2012 and 2013 (12.4 ) Change in regulatory flow-through tax adjustments (8.8 ) Increase in income tax at statutory rates (19.1 ) Total increase in Idaho Power net income 8.6 Other net changes (net of tax) 0.8 Net income attributable to IDACORP, Inc. - December 31, 2013 $ 182.4 38-------------------------------------------------------------------------------- Table of Contents IDACORP's net income increased $9.4 million for the year ended December 31, 2013, when compared to 2012, driven largely by increased operating income of $52.1 million at Idaho Power and enhanced by an $11.6 million gain on the 2013 sale of investments in securities. Higher rates implemented during 2012, primarily related to the full year inclusion in base rates of the Langley Gulch power plant, increased operating income for 2013 by $30.1 million compared to 2012. The impact of the increased rates was partially offset by decreased AFUDC and increased depreciation expense, both associated with the full year inclusion of the Langley Gulch plant in base rates. Higher sales volumes per customer, attributed to extreme winter and summer temperatures, and higher irrigation sales increased operating income by $18.0 million. Greater sales volumes due to growth in the number of customers added $8.9 million to operating income for the year compared to the same period in 2012.

The increases in operating income were slightly offset by the sharing mechanism under the December 2011 regulatory settlement agreement, with a combined $2.3 million higher pension expense and provision for revenue sharing recorded in 2013 compared to 2012. Also offsetting the overall increase in operating income was higher income tax expense resulting from greater 2013 pre-tax earnings at Idaho Power and income tax method changes affecting both comparative periods.

Effect of Income Taxes and Tax Method Changes on Results Income tax expense related to income tax accounting method changes increased $12.4 million for 2013 when compared to 2012. In 2012, Idaho Power recorded an income tax benefit of $7.8 million for years prior to 2011 for the cumulative tax adjustment of a method change related to its capitalized repairs deduction for transmission and distribution property. By contrast, during 2013 Idaho Power recorded incremental income tax expense of $4.6 million as a result of a method change related to its capitalized repairs deduction for generation assets due to a change in income tax law that occurred in September 2013. Net regulatory flow-through tax adjustments at Idaho Power were $8.8 million lower for 2013 as compared to 2012, primarily due to greater capitalized repairs deductions in 2012. This method change only impacted the cumulative tax adjustment for years prior to 2013, and Idaho Power does not expect a change to net regulatory flow-through tax adjustments for subsequent years as a result of the method change.

Effect of Sharing on Operating Income 2013 2012 Variance Additional pension expense funded through sharing $ (16.5 ) $ (14.6 ) $ (1.9 ) Provision against current revenue as a result of sharing (7.6 ) (7.2 ) (0.4 ) Total $ (24.1 ) $ (21.8 ) $ (2.3 ) During 2013, Idaho Power recorded a total of $24.1 million related to a December 2011 Idaho regulatory settlement agreement, which requires sharing with Idaho customers a portion of 2013 Idaho-jurisdiction earnings exceeding a 10.0 percent return on year-end equity in the Idaho jurisdiction. In accordance with the terms of the settlement agreement, of the total, $16.5 million was recorded as additional pension expense and $7.6 million was recorded as a provision against current revenues to be refunded to customers through a future rate reduction.

The settlement agreement is described further in "Regulatory Matters" in this MD&A. By comparison, in 2012 Idaho Power recorded a total of $21.8 million related to the December 2011 settlement agreement. Of the total recorded in 2012, $14.6 million was recorded as additional pension expense and $7.2 million was recorded as a provision against revenues.

Key Operating and Financial Metric Estimates for 2014 IDACORP's and Idaho Power's estimates, as of the date of this report, for 2014 metrics are as follows: 2014 Estimate 2013 Actual Idaho Power Operating & Maintenance Expense (millions) $335-$345 $ 349 Idaho Power Additional Amortization of ADITC (millions) Less than $5 None Idaho Power Capital Expenditures, excluding AFUDC (millions) $280-$295 $ 228 Idaho Power Hydroelectric Generation (million MWh) 5.0-7.0 5.7 39-------------------------------------------------------------------------------- Table of Contents 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 during the year ended December 31, 2013. In this analysis, the results for 2013 are compared to 2012 and the results for 2012 are compared to 2011. In MD&A, MWh and dollar amounts in tables, other than earnings per share, are in thousands unless otherwise indicated.

Utility Operations The table below presents Idaho Power's energy sales and supply (in thousands of MWh) for the last three years.

Year Ended December 31, 2013 2012 2011 General business sales 14,619 14,085 13,734 Off-system sales 1,683 2,183 3,635 Total energy sales 16,302 16,268 17,369 Hydroelectric generation 5,656 7,956 10,937 Coal generation 6,327 5,227 4,820 Natural gas and other generation 1,576 676 138 Total system generation 13,559 13,859 15,895 Purchased power 3,902 3,670 2,751 Line losses (1,159 ) (1,261 ) (1,277 ) Total energy supply 16,302 16,268 17,369 Sales Volume and Generation: In 2013, general business sales volume across all customer classes increased by 0.5 million MWh compared to the prior year, mostly related to increased residential customer usage attributable to more extreme weather conditions. Off-system sales volume decreased by 0.5 million MWh in 2013 as decreases in output from hydroelectric resources and a small increase in general business customer load reduced surplus power available for sale.

Hydroelectric generation provided 42 percent of Idaho Power's total system generation during 2013. Hydroelectric generation in 2013 was 67 percent of the annual median generation of 8.4 million MWh, which is based on median hydrologic conditions as derived from the Snake River Basin historical stream flow record normalized to reflect the current level of water resource development. The reductions in hydroelectric generation from 2011 to 2013 reflect declining hydroelectric generating conditions that existed during the three-year period.

The decrease in hydroelectric generation during 2013 led to an increased utilization of coal-fired and natural-gas fired generation. The first full year of operations of the Langley Gulch natural gas-fired power plant allowed for less reliance on purchased power to replace the decreased hydroelectric generation.

40-------------------------------------------------------------------------------- Table of Contents General Business Revenues: The table below presents Idaho Power's general business revenues, MWh sales, and number of customers for the last three years.

Year Ended December 31, 2013 2012 2011 Revenue Residential $ 513,914 $ 431,555 $ 405,982 Commercial 281,009 241,519 220,962 Industrial 165,941 145,054 140,701 Irrigation 159,242 137,424 104,635 Total 1,120,106 955,552 872,280 Provision for sharing (7,602 ) (7,151 ) (27,099 ) Deferred revenue related to HCC relicensing (10,776 ) (10,636 ) (10,636 ) AFUDC(1) Total general business revenues $ 1,101,728 $ 937,765 $ 834,545 Volume of Sales (MWh) Residential 5,365 5,039 5,146 Commercial 3,975 3,865 3,815 Industrial 3,182 3,133 3,100 Irrigation 2,097 2,048 1,673 Total MWh sales 14,619 14,085 13,734 Number of customers at year-end Residential 422,188 416,020 411,487 Commercial 66,734 65,920 65,226 Industrial 115 119 121 Irrigation 19,398 19,045 18,736 Total customers 508,435 501,104 495,570 (1) As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

Changes in rates and changes in customer demand are the primary causes of fluctuations in general business revenue from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last three years.

Rates are seasonally adjusted and based on a tiered rate structure that provides for higher rates during peak load periods. These seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.

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 and the timing of precipitation during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps. For purposes of illustration, Boise, Idaho weather-related information for the last three years is presented in the following table: Year Ended December 31, 2013 2012 2011 Normal Heating degree-days(1) 6,032 4,723 5,554 5,514 Cooling degree-days(1) 1,320 1,274 1,076 942 (1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.

While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service territory, the greater Boise area has the majority of Idaho Power's customers.

41-------------------------------------------------------------------------------- Table of Contents General Business Revenues - 2013 Compared to 2012: General business revenue increased $164.0 million in 2013 compared to 2012. Specific factors affecting general business revenues are discussed below.

• Rates. Rate changes combined to increase general business revenue by $130.8 million. The revenue impact of several of the rate changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense increased $42.0 million in 2013 due to the change in the corresponding Idaho PCA true-up rate in the current year.

The PCA mechanism and its mechanics are discussed in detail below in this MD&A.

• Usage. Higher usage per customer, primarily driven by residential customers, increased general business revenue by $27.9 million. While usage increased across all customer classes, residential usage per customer was 5.2 percent higher for 2013 due largely to more extreme summer and winter temperatures.

• Customers. Customer growth contributed to the increase in overall MWh sales, increasing revenue $12.3 million. Customer growth from 2012 to 2013 was 1.5 percent. The positive impact of customer growth was partially offset by a $6.6 million decrease in revenues resulting from the termination in 2012 of an electric service agreement with Hoku Materials, Inc. (Hoku). Combined, these changes increased general business revenues by $5.7 million.

• Sharing. The overall increase in general business revenue was impacted by Idaho Power's revenue sharing mechanism. This mechanism, which was in place for both 2012 and 2013, originates from a December 2011 Idaho regulatory settlement agreement that requires sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE.

Amounts allocated for customer sharing as a result of the sharing mechanism are recorded as a reduction to general business revenue.

Reductions of $7.6 million and $7.2 million were recorded in 2013 and 2012, respectively, resulting in a net decrease to general business revenue of $0.4 million in 2013.

General Business Revenues - 2012 Compared to 2011: General business revenue increased $103.2 million in 2012 compared to 2011. The factors affecting general business revenues are discussed below.

• Rates. Rate changes combined to increase general business revenue by $73.5 million in 2012 compared to 2011. The revenue impact of several of these rate changes was directly offset by associated changes in operating expenses. For example, Idaho-jurisdiction pension expense recovery rate changes were fully offset by increased pension expense.

• Sharing. A part of the increase in 2012 revenue resulted from revenue sharing mechanisms associated with two Idaho regulatory agreements that provide for the sharing of Idaho-jurisdiction earnings exceeding a specified Idaho ROE. As noted above, the amount to be shared through future rate reduction is recorded as a current reduction to general business revenue. Reductions of $7.2 million and $27.1 million were recorded in 2012 and 2011, respectively, resulting in a net increase to general business revenue of $19.9 million in 2012 compared to 2011. The smaller amount recorded in 2012 when compared with the prior year is partially due to changes in the terms of the mechanism in place each year, described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

• Usage. For 2012, higher usage per customer increased general business revenue $13.7 million compared to 2011. Irrigation usage per customer was 20.9 percent higher for 2012 when compared with 2011 due to agricultural growing conditions, including warm temperatures that allowed for the earlier planting of crops, and lower relative springtime precipitation, which resulted in greater electricity use to operate irrigation pumps.

• Customers. Termination of service to Hoku during 2012 under an electric service agreement, offset by moderate customer growth, decreased general business revenues by $3.9 million. Customer count grew 1.1 percent from 2011 to 2012.

In March 2009, the IPUC approved an electric service agreement between Idaho Power and Hoku, to provide electric service to Hoku's polysilicon production facility then under construction in Idaho. The initial term of the agreement was four years beginning December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. As a result of Hoku's failure to remain timely in payments, Idaho Power terminated its provision of electric service under the electric service agreement in May 2012. Idaho Power applied a $2 million deposit to Hoku's April, May, and June 2012 invoices and fully exhausted the deposit required by the agreement. For full year 2012 and prior to termination of service, Idaho Power had anticipated contract payments of $5.4 million that are unaffected by the PCA mechanism and $6.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $12.2 million. As a result of termination of service and non-payment, Idaho Power recognized $6.6 million of full 42-------------------------------------------------------------------------------- Table of Contents year 2012 revenues that are unaffected by the PCA mechanism and no revenues that are affected by and flow through the PCA mechanism. The impact of non-payment and associated decreases in revenue on 2012 net income was tempered in part by a decrease in costs Idaho Power would have incurred in connection with the provision of service to Hoku and the impact of the PCA mechanism.

Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power's off-system sales for the last three years.

Year Ended December 31, 2013 2012 2011 Revenue $ 54,473 $ 61,534 $ 101,602 MWh sold 1,683 2,183 3,635 Revenue per MWh $ 32.37 $ 28.19 $ 27.95 Off-System Sales - 2013 Compared to 2012: Off-system sales revenue decreased by $7.1 million, or 11 percent, in 2013 as a result of lower volumes of surplus power available for sale. Sales volumes decreased by 23 percent due to lower output from hydroelectric plants due to unfavorable hydroelectric generating conditions (as a result of lower snow pack and spring season run-off) and an increase in general business customer loads.

Off-System Sales - 2012 Compared to 2011: Off-system sales revenue decreased by $40.1 million, or 39 percent, in 2012 as compared to 2011, as a result of lower volumes. Sales volumes decreased by 40 percent due to lower output from hydroelectric plants due to unfavorable hydroelectric generating conditions and a small increase in load needs when compared with 2011.

Other Revenues: The table below presents the components of other revenues for the last three years.

Year Ended December 31, 2013 2012 2011 Transmission services and other $ 51,260 $ 50,126 $ 48,918 Energy efficiency 35,637 27,300 37,663 Total other revenues $ 86,897 $ 77,426 $ 86,581 Other Revenues - 2013 Compared to 2012: Other revenues increased $9.5 million in 2013, mainly due to an increase in energy efficiency revenues of $8.3 million, due to an order issued by the IPUC allowing Idaho Power to recover custom efficiency program incentive payments between January 1, 2011 and June 1, 2013, through the energy efficiency rider. Based on the order, $14.3 million of other revenue as well as energy efficiency program expense was recognized in the second quarter of 2013. The impact of the order was offset by decreased utilization of demand response programs during 2013.

Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with a similar amount of revenues recorded in other revenues, resulting in minimal net impact on earnings. 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. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected.

Other Revenues - 2012 Compared to 2011: Other revenues decreased $9.2 million in 2012 as compared to 2011, mainly due to: • a decrease in energy efficiency revenues of $10.4 million, primarily due to demand response incentive payments to customers, which had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior, were recorded as purchased power expense and recovered through the PCA mechanism during 2012, as discussed in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report; and • an increase of $1.7 million in transmission system revenues, resulting principally from increases in wheeling services attributable to increases in FERC transmission rates that took effect on October 1, 2011 and October 1, 2012.

43-------------------------------------------------------------------------------- Table of Contents Purchased Power: The table below presents Idaho Power's purchased power expenses and volumes for the last three years.

Year Ended December 31, 2013 2012 2011 Expense PURPA contracts $ 131,338 $ 117,618 $ 90,251 Other purchased power (including wheeling) 85,038 64,838 73,082 Demand response incentive payments 4,203 14,479 3 Total purchased power expense $ 220,579 $ 196,935 $ 163,336 MWh purchased PURPA contracts 2,127 1,961 1,495 Other purchased power 1,775 1,709 1,256 Total MWh purchased 3,902 3,670 2,751 Cost per MWh from PURPA contracts $ 61.75 $ 59.98 $ 60.36 Cost per MWh from other purchased power $ 47.91 $ 37.94 $ 58.19 Weighted average - all sources (excluding demand response incentive payments) $ 55.45 $ 49.72 $ 59.37 The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase more 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 anticipated 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 transaction prices.

Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms; thus, the primary impact of the increased expense associated with PURPA power purchases is a corresponding increase in customer rates.

Purchased Power - 2013 Compared to 2012: Purchased power expense increased $23.6 million, or 12 percent, in 2013, principally due to additional PURPA wind generation that came on-line, as well as less favorable hydroelectric generating conditions, which increased the need to purchase power from third parties. The volume of power purchased through PURPA contracts increased 8 percent, contributing to a $13.7 million increase in PURPA power purchase expense in 2013, while MWh purchased through other sources increased 4 percent. Reductions in demand response program costs, due to temporary suspension of two programs in 2013, partially offset the increased expenses related to power purchases.

Purchased Power - 2012 Compared to 2011: Purchased power expense increased $33.6 million, or 21 percent, in 2012 as compared to 2011, principally due to additional PURPA wind generation that came on-line and less favorable hydroelectric generating conditions. The volume of power purchased through PURPA contracts increased 31 percent, contributing to a $27.4 million increase in PURPA power purchase expense in 2012 compared to 2011, while MWh purchased through other sources increased 36 percent. Overall MWh purchases increased due to less favorable hydroelectric generating conditions decreasing Idaho Power's volume of self-generated power. The increase in MWh purchased was partially offset by a reduction in expense per MWh purchased. Average wholesale electricity prices were lower in 2012 relative to 2011 as a result of lower natural gas prices in the region, which reduced generation costs and, correspondingly, power prices. In addition, $14.5 million of demand response program charges were recorded as purchased power expense in 2012. These costs had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior.

44-------------------------------------------------------------------------------- Table of Contents Fuel Expense: The table below presents Idaho Power's fuel expenses and generation at its thermal generating plants for the last three years.

Year Ended December 31, 2013 2012 2011 Expense Coal $ 160,277 $ 134,501 $ 119,845 Natural gas and other thermal 54,205 24,912 11,697 Total fuel expense $ 214,482 $ 159,413 $ 131,542 MWh generated Coal 6,327 5,227 4,820 Natural gas and other thermal 1,576 676 138 Total MWh generated 7,903 5,903 4,958 Cost per MWh Coal $ 25.33 $ 25.73 $ 24.86 Natural gas and other thermal 34.39 36.85 84.76 Weighted average, all sources 27.14 27.01 26.53 Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh (such as the cost per MWh for natural gas and other in 2012 and 2013 compared to 2011) are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.

Fuel Expense - 2013 Compared to 2012: In 2013, fuel expense increased $55.1 million, or 35 percent, compared to 2012, due principally to the following factors: • Idaho Power's Langley Gulch natural gas-fired power plant came on line on June 29, 2012. Operation of the plant accounted for $23.9 million of the increase in fuel expense. Idaho Power operated the plant primarily to serve peak load, to integrate intermittent resources, and for economic dispatch opportunities. During 2013, Idaho Power relied more on Langley Gulch and other gas plants to meet customer loads as a result of the decline in hydroelectric generation compared to the same period in 2012.

• generation from coal-fired facilities increased 21 percent for 2013. This increase in generation accounted for $25.6 million of the increase in fuel expense compared to 2012. During 2013, higher wholesale power prices and lower hydroelectric generation when compared with 2012 increased Idaho Power's reliance on its coal-fired plants to meet customer loads.

Fuel Expense - 2012 Compared to 2011: Fuel expense increased $27.9 million, or 21 percent, compared to 2011 due to higher output at the coal-fired power plants and at the Langley Gulch plant. The output at the coal-fired plants was up 0.4 million MWh, or 8 percent, in 2012. The increased dispatch was primarily caused by lower hydroelectric generation in 2012 than in 2011.

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year.

Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices and volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric generation volume, thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power has PCA mechanisms for both the Idaho and Oregon jurisdictions. These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and the company (5 percent), with the exception of PURPA power purchases and demand-response program payments, which are allocated 100 percent to customers. Because of the PCA 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, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

45-------------------------------------------------------------------------------- Table of Contents The following table presents the components of the Idaho and Oregon PCA mechanisms for the last three years.

Year Ended December 31, 2013 2012 2011 Idaho power supply cost (deferral) accrual $ (67,127 ) $ (45,064 ) $ 27,768 Oregon power supply cost (deferral) accrual - (1,523 ) 1,523 Amortization of prior year authorized balances 27,590 (14,503 ) 9,206 Total power cost adjustment expense $ (39,537 ) $ (61,090 ) $ 38,497 The power supply accruals or deferrals represent the portion of that period's power supply cost fluctuations accrued or deferred under the PCA mechanisms. If actual power supply costs are greater than the amount forecasted in PCA rates, which was the case for 2013 and 2012, most of the excess cost is deferred.

Accruals, such as those recorded in 2011, represent additional costs being recorded as a result of actual power supply costs being less than the amount forecasted and recovered in PCA rates. The amortization of the prior year's balances represents the amounts being collected or refunded in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).

PCA Mechanisms -2013 Compared to 2012: Actual net power supply costs increased in 2013 relative to 2012, resulting in a change of $20.5 million-from deferrals of $46.6 million to $67.1 million. The $27.6 million of amortization offsets the net collection from customers of prior years' deferrals.

PCA Mechanisms -2012 Compared to 2011: Actual net power supply costs increased in 2012 relative to 2011, resulting in a change of $75.9 million-from accruals of $29.3 million to deferrals of $46.6 million. The $14.5 million of amortization reflects the net refunding to customers of prior years' accruals.

Other Operations and Maintenance Expenses: The changes in operations and maintenance (O&M) expenses for the periods presented are discussed below.

O&M - 2013 Compared to 2012: Other O&M expense decreased by $0.2 million in 2013 as compared to 2012, a decrease of less than one percent, due to: • pension expense increased $1.9 million as the sharing mechanism in place during both years resulted in higher sharing-related pension expense in 2013; • other O&M expenses were $1.3 million lower reflecting business optimization efforts; • labor-related expenses increased by $1.5 million, as a result of increased labor and benefits costs; and • O&M expenses associated with hydroelectric generation were $2.3 million lower, primarily due to water lease payments made in 2012 that were not made in 2013 because less water associated with these leases was available in 2013.

O&M - 2012 Compared to 2011: A $10.4 million increase in other O&M expense in 2012 as compared to 2011 was principally due to the following: • $9.0 million in higher administrative expenses related to various increases in consultant costs, software licenses and maintenance, insurance reserves, and other purchased services. A significant portion of the increase related to a lower reimbursement from the U.S. Department of Energy for Smart Grid-related items in 2012 compared to 2011; • increased payroll and other benefit expenses of $6.8 million related to normal increases in employee wages and costs of providing employee benefits; and • a $3.2 million increase in transmission system maintenance expenses primarily related to line inspection costs; offset by • a $9.1 million decrease in thermal plant O&M related to costs for maintenance outages that occurred in 2011 that did not recur in 2012, as well as lower overall maintenance costs and consumable supplies due to lower utilization of these plants during the first half of 2012. The lower utilization was predominantly driven by low wholesale energy prices in the region during that period.

46-------------------------------------------------------------------------------- Table of Contents Gain on Sale of Investments In 2013, Idaho Power recognized an $11.6 million gain on the sale of marketable securities. These investments relate to the Rabbi trust designated to provide funding for Idaho Power's obligations under its Security Plan for Senior Management Employees. Gross proceeds from the sale were $25.7 million.

Income Taxes Income Tax Expense: IDACORP's and Idaho Power's income tax expense for 2013 increased significantly relative to 2012, primarily as a result of greater Idaho Power pre-tax earnings in 2013 and an income tax accounting method change adjustment. Income tax expense in 2012 increased significantly compared to 2011, principally as a result of the tax benefits from U.S. Internal Revenue Service (IRS) examination settlements recorded in 2011 and greater Idaho Power pre-tax earnings in 2012. 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. The amounts reported by IDACORP for income tax expense incorporate the impact of adoption in 2013, with retrospective effect, of an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. The method change is discussed in Note 1 - "Summary of Significant Accounting Policies" in the notes to the consolidated financial statements included in this report.

Impact of New Tax Law: On September 13, 2013, the U.S. Treasury Department and IRS issued final regulations addressing the deduction or capitalization of expenditures related to tangible property. The regulations are generally effective for tax years beginning on or after January 1, 2014. In connection with the issuance of the regulations, Idaho Power assessed and estimated the impact of a method change associated with the electric generation property portion of the capitalized repairs method it adopted in fiscal year 2010. Idaho Power intends to make this method change in either its 2013 or 2014 tax year and as such recorded a $4.6 million income tax expense in the third quarter of 2013 related to the cumulative method change adjustment that will be necessary to effectuate the change. IDACORP and Idaho Power do not expect that compliance with these regulations will have a material adverse impact on their financial positions, results of operations, or cash flows. Additionally, the companies do not expect this method change or the regulations to have a material adverse effect on Idaho Power's on-going capitalized repairs tax deduction. However, given the complexity of the new regulations, as IDACORP and Idaho Power continue to evaluate the impact of the regulations the companies may be required to record additional tax impacts in future periods.

Bonus Depreciation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) include provisions for the extension and increase of bonus depreciation.

Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes. 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. In addition, the American Taxpayer Relief Act of 2012 extended 50 percent bonus depreciation to 2013. Idaho Power has included an estimated bonus deprecation deduction in its current income tax provision. The estimated deduction would reduce Idaho Power's 2013 federal income tax liability by approximately $20 million. Idaho Power will evaluate the impacts bonus depreciation could have on its 2014 income taxes should another extension of the federal law be enacted.

The state of Idaho did not conform to the federal bonus depreciation rules for 2010-2013.

Net Operating Loss and Tax Credit Carryforwards: IDACORP finished 2013 with a federal net operating loss carryforward of $87 million, a federal general business tax credit carryforward of $111 million, and a $37 million Idaho investment tax credit carryforward. Based on the expiration dates of the credits, as described in Note 2 - "Income Taxes - Tax Credit Carryforwards and Net Operating Loss Carryforwards" to the consolidated financial statements included in this report, these amounts are expected to provide future cash flows.

47-------------------------------------------------------------------------------- Table of Contents LIQUIDITY AND CAPITAL RESOURCES Overview Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power's construction expenditures in 2013 equaled those of 2012, with expenditures for property, plant and equipment, excluding AFUDC, totaling $228 million each year. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures in the range of $1.47 billion to $1.56 billion over the period from 2014 through 2018.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power periodically files 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.

Idaho Power uses operating and capital budgets to control operating costs and capital expenditures, and has also been focusing on optimizing its business operations, which has included controlling operating and maintenance costs through process review and improvement initiatives. A significant focus for 2014 will be to continue to optimize operations and control costs and to generate sufficient operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

As of February 14, 2014, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included: • their respective $125 million and $300 million revolving credit facilities; • IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 22, 2013, which may be used for the issuance of debt securities and common stock, including up to 3 million shares of IDACORP common stock available for issuance under IDACORP's sales agency agreement executed in July 2013; • Idaho Power's shelf registration statement, filed with the SEC jointly with IDACORP on May 22, 2013, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance under a selling agency agreement executed in July 2013 and pursuant to state regulatory authority; and • IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities.

IDACORP and Idaho Power have no significant long-term debt maturities until 2018. Based on planned capital expenditures and operating and maintenance expenses for 2014, and in light of the success of cost-controlling efforts to-date, the companies believe they will be able to meet capital requirements during 2014 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business. IDACORP and Idaho Power would expect to meet any cash shortfall with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets. At the same time, IDACORP and Idaho Power monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account potential future needs. As a result, IDACORP may issue debt securities or may issue common stock under the existing continuous equity program, and Idaho Power may issue debt securities in 2014 if the companies believe terms available in the capital markets are particularly favorable and that issuances would be financially prudent. In 2013, while there was a short period of reduced liquidity and higher borrowing costs in the commercial paper markets, which IDACORP and Idaho Power attributed largely to uncertainty associated with the federal debt ceiling debate, IDACORP and Idaho Power did not experience any material limitations in accessing credit markets on reasonable terms.

Idaho Power has a number of first mortgage bonds outstanding with interest rates higher than those Idaho Power obtained for the issuance of first mortgage bonds with comparable maturity dates during 2013. While many of those series of first mortgage bonds contain optional redemption provisions, Idaho Power would be required, under the terms of those series of first mortgage bonds, to pay amounts in excess of the principal balance of the first mortgage bonds on the date of redemption. The redemption amount is generally based on the sum of the present values of the remaining scheduled payments of principal and interest on the first mortgage bonds to be redeemed, calculated at a specified discount rate. While Idaho Power periodically analyzes whether partial or full early redemption of one or more series of first mortgage bonds is desirable, these "make-whole" premiums often fully or partially eliminate the potential benefit of early redemption.

48-------------------------------------------------------------------------------- Table of Contents IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2013, IDACORP's and Idaho Power's capital structures were as follows: IDACORP Idaho Power Debt 48% 49% Equity 52% 51% Operating Cash Flows IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, and pension plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.

IDACORP's and Idaho Power's operating cash inflows in 2013 were $306 million and $290 million, respectively, increases of $56 million and $32 million, respectively, compared to 2012. In addition to increased pre-tax earnings, significant items that affected the companies' operating cash flows in 2013 relative to 2012 included: • Idaho Power made $30 million of cash contributions to its defined benefit pension plan in 2013, compared to $44.3 million of cash contributions during 2012; • cash outflows related to income taxes increased by approximately $25 million for Idaho Power, as cash payments for income taxes totaled $10 million in 2013, compared with net refunds from IDACORP for income tax of $15 million in 2012. IDACORP's cash outflows related to incomes taxes remained relatively flat at $1.4 million in 2013 and 2012; • changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating cash inflows by $28 million; and • changes in working capital balances due primarily to timing. Increases in receivable balances reduced cash flows by approximately $27 million, primarily as a result of increased year-end sales in 2013 compared to 2012. Fluctuations in accounts payables and other accrued liabilities reduced cash flows by $11 million, largely as a result of reduced accruals for PURPA-related payables. Other current liabilities increased cash flows by $10 million primarily due to customer deposits returned in 2012.

IDACORP's and Idaho Power's operating cash inflows in 2012 were $249 million and $258 million, respectively, decreases of $61 million and $35 million, respectively, compared to 2011. In addition to increased pre-tax earnings, significant items that affected the companies' operating cash flows in 2012 relative to 2011 included: • Idaho Power made contributions of $44.3 million to its defined benefit pension plan in 2012, compared with an $18.5 million cash contribution in 2011; • cash outflows related to income taxes increased by $14 million for both IDACORP and Idaho Power. IDACORP paid income taxes of $1 million in 2012 compared with receiving $12 million of income tax refunds in 2011. Idaho Power's net refunds from IDACORP for income tax were $15 million for 2012, compared with $1 million in 2011; • changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $100 million, as Idaho Power collected $24 million less of previously deferred costs due to decreases in PCA rates and incurred $76 million less in the current year PCA accrual, as compared with 2011; and • Idaho Power's joint venture, BCC, made net distributions to Idaho Power of $18 million for 2012, as compared to a $3 million net contribution for 2011. The change from year to year is the result of BCC having more cash to distribute in 2012 than 2011. There were less capital investments in 2012 than 2011, less operating cash invested in coal inventory 49-------------------------------------------------------------------------------- Table of Contents in 2012 than 2011, and higher reclamation activities in 2012 than 2011 causing an increase in the amount of disbursements from the reclamation trust to BCC.

Investing Cash Flows Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power's generation, transmission, and distribution facilities. These capital expenditures address peak demand growth, aging plant and equipment, and customer growth. Idaho Power's construction expenditures were $235 million, $240 million, and $338 million in 2013, 2012, and 2011, respectively. Construction expenditures during 2011 and 2012 were heavily impacted by construction costs for the Langley Gulch power plant.

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, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2011, 2012, and 2013: • on March 2, 2011, Idaho Power repaid at maturity $120 million of its 6.60% first mortgage bonds due 2011; • on April 13, 2012, Idaho Power issued $75 million in principal amount of 2.95% first mortgage bonds due 2022 and $75 million in principal amount of 4.30% first mortgage bonds due 2042; • in May 2012, Idaho Power redeemed prior to maturity $100 million of 4.75% first mortgage bonds due in November 2012; • on April 8, 2013, Idaho Power issued $75 million in principal amount of 2.50% first mortgage bonds due 2023 and $75 million in principal amount of 4.00% first mortgage bonds due 2043; • on October 1, 2013 Idaho Power repaid at maturity $70 million of its 4.25% first mortgage bonds; • IDACORP and Idaho Power paid dividends of $79 million, $69 million, and $60 million in 2013, 2012, and 2011, respectively; • Idaho Power received capital contributions of $8 million and $16 million from IDACORP in 2012 and 2011, respectively; and • IDACORP's net change in commercial paper borrowings was a reduction of $15 million and $13 million for 2013 and 2011, respectively, and an increase of $16 million for 2012.

Financing Programs and Available Liquidity Idaho Power First Mortgage Bonds: Idaho Power's issuance of long-term indebtedness is subject to the approval of the IPUC, OPUC, and Wyoming Public Service Commission (WPSC). In February 2013, Idaho Power filed applications with the IPUC, OPUC, and WPSC to renew its long-term debt financing authority. In April 2013, Idaho Power received orders from the IPUC, OPUC, and WPSC authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and first mortgage bonds, subject to conditions specified in the orders. Authority from the IPUC is through April 9, 2015, though Idaho Power may request an extension by letter filed with the IPUC prior to that date. The OPUC's and WPSC's orders do not impose a time limitation for issuances, but the OPUC order does impose a number of other conditions, including a maximum interest rate limit of 7 percent.

On May 22, 2013, IDACORP and Idaho Power filed a joint shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of, in the case of Idaho Power, an unspecified principal amount of its first mortgage bonds and debt securities. On July 12, 2013, Idaho Power entered into a Selling Agency Agreement with eight banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million in aggregate principal amount of first mortgage bonds, Series J (Series J Notes), under Idaho Power's Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented (Indenture). Also on July 12, 2013, Idaho Power entered into the Forty-seventh Supplemental Indenture, dated as of July 1, 2013, to the Indenture. The Forty-seventh Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series J Notes. As of the date of this report, Idaho Power has not sold any first mortgage bonds or debt securities under the May 2013 shelf registration statement or Selling Agency Agreement and does not anticipate any issuances during 2014, except for transactions the company believes may be particularly opportunistic based on capital market conditions.

50-------------------------------------------------------------------------------- Table of Contents The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture, market conditions, regulatory authorizations, and covenants contained in other financing agreements. The Indenture limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of December 31, 2013, Idaho Power could issue approximately $1.4 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of December 31, 2013 was limited to approximately $409 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust. Refer to Note 4 - "Long-Term Debt" to the consolidated financial statements included in this report for more information regarding long-term financing arrangements.

IDACORP and Idaho Power Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin.

The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less 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, including, in some instances, 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, 2013, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their 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 certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At December 31, 2013, IDACORP and Idaho Power believe they were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of their respective debt covenants during 2014.

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurring of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. 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 51-------------------------------------------------------------------------------- Table of Contents 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.

While the credit facilities provide for an original maturity date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On October 12, 2012, IDACORP and Idaho Power executed First Extension Agreements with the lenders, extending the maturity date under both credit agreements to October 26, 2017. On October 8, 2013, IDACORP and Idaho Power executed Second Extension Agreements with the lenders, extending the maturity date under both credit agreements to October 26, 2018. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extensions.

Without additional approval from the IPUC, the OPUC, and the WPSC, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

IDACORP Equity Programs: On May 22, 2013, IDACORP filed a shelf registration statement with the SEC, which became effective upon filing, for the offer and sale of an unspecified number of shares or dollar amount of IDACORP's common stock. On July 12, 2013, IDACORP entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC (BNYMCM), under which IDACORP may offer and sell up to 3 million shares of its common stock from time to time through BNYMCM as IDACORP's agent. The Sales Agency Agreement replaces a similar sales agency agreement, dated December 16, 2011, between IDACORP and BNYMCM, that provided for the sale of up to 3 million shares of IDACORP common stock. IDACORP did not sell any shares of its common stock under the December 2011 sales agency agreement. IDACORP has no obligation to sell any minimum number of shares under the Sales Agency Agreement. As of the date of this report, 3 million shares of IDACORP common stock remain available for sale under the Sales Agency Agreement with BNYMCM.

Effective July 1, 2012, IDACORP discontinued original issuances of common stock and instructed the plan administrators to use market purchases of IDACORP common stock for purposes of acquiring IDACORP common stock for the IDACORP, Inc.

Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan. However, IDACORP may determine at any time to resume original issuances of common stock under those plans. As noted above, an important component of that determination will be IDACORP's and Idaho Power's capital structure. Under the dividend reinvestment and employee-related stock purchase plans in effect prior to July 1, 2012, IDACORP issued 111,380 shares in 2012 and 211,276 shares in 2011 for proceeds of $4.5 million and $8.2 million, respectively.

IDACORP issued 8,766 shares of IDACORP common stock in 2013, 8,600 shares in 2012, and 255,746 shares in 2011, in connection with the exercise of stock options, for proceeds of $0.3 million, $0.4 million, and $9.4 million, respectively.

IDACORP and Idaho Power Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above.

IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

Available Short-Term Borrowing Liquidity The following table outlines available short-term borrowing liquidity as of the dates specified.

December 31, 2013 December 31, 2012 IDACORP(2) Idaho Power IDACORP(2) Idaho Power Revolving credit facility $ 125,000 $ 300,000 $ 125,000 $ 300,000 Commercial paper outstanding (54,750 ) - (69,700 ) - Identified for other use(1) - (24,245 ) - (24,245 ) Net balance available $ 70,250 $ 275,755 $ 55,300 $ 275,755 (1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds were unable to sell the bonds to third parties.

(2) Holding company only.

52-------------------------------------------------------------------------------- Table of Contents At February 14, 2014, IDACORP had no loans outstanding under its credit facility and $45.6 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the years ended December 31, 2013 and 2012.

December 31, 2013 December 31, 2012 IDACORP(1) Idaho Power IDACORP(1) Idaho Power Commercial paper: Year end: Amount outstanding $ 54,750 $ - $ 69,700 $ - Weighted average interest rate 0.34 % - % 0.50 % - % Daily average amount outstanding during the year $ 61,121 $ 2,209 $ 57,947 $ 3,578 Weighted average interest rate during the year 0.39 % 0.43 % 0.48 % 0.47 % Maximum month-end balance $ 67,150 $ 16,600 $ 69,800 $ 12,000 (1) Holding company only.

Impact of Credit Ratings on Liquidity and Collateral Obligations IDACORP's and Idaho Power's access to capital markets, including the commercial paper market, and their respective financing costs in those markets, depends in part on their respective credit ratings. The following table outlines the ratings of Idaho Power's and IDACORP's securities, and the ratings outlook, by Standard & Poor's Ratings Services and Moody's Investors Service as of the date of this report: S&P Moody's IDACORP Idaho Power IDACORP Idaho Power Corporate Credit Rating/Long-Term Issuer Rating BBB BBB Baa 1 A3 Senior Secured Debt None A- None A1 Senior Unsecured Debt None BBB None A3 Short-Term Tax-Exempt Debt None BBB/A-2 None A3/ VMIG-2 Commercial Paper A-2 A-2 P-2 P-2Senior Unsecured Credit Facility None None Baa 1 A3 Rating Outlook Stable Stable Stable Stable These security ratings reflect the views of the ratings 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, 2013, Idaho Power had posted $4.1 million of performance 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 requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts 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 current energy and fuel portfolio and market conditions as of December 31, 2013, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $13.0 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral, through sensitivity analysis.

Capital Requirements Idaho Power's construction expenditures, excluding AFUDC, were $228 million during the year ended December 31, 2013. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2014 through 53-------------------------------------------------------------------------------- Table of Contents 2018 (in millions of dollars). Given the uncertainty associated with the timing of infrastructure projects and associated expenditures, actual expenditures and their timing could deviate substantially from those set forth in the table.

2014 2015 2016-2018 Ongoing capital expenditures (excluding item listed $ 235-245 $ 275-290 $ 855-900 below in this table) Jim Bridger plant selective catalytic reduction 45-50 40-45 20-25 equipment (detailed below) Total $ 280-295 $ 315-335 $ 875-925 Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The most notable projects are described below.

Boardman-to-Hemingway Transmission Line: The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet future resource needs. The Boardman-to-Hemingway line was included in the preferred resource portfolio in Idaho Power's 2013 IRP. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Assuming both other participants fund their full share of the total cost of the permitting phase of the project, Idaho Power's estimated share of the cost of the permitting phase of the project is approximately $17 million, including AFUDC. Total cost estimates for the project are between $890 million and $940 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's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

The permitting phase of the Boardman-to-Hemingway project is subject to review and approval by the U.S. Bureau of Land Management (BLM) (as the lead federal agency on behalf of other federal agencies), the U.S. Forest Service, and the Oregon Department of Energy. Idaho Power currently expects the BLM to issue a draft environmental impact statement (EIS) for the project during 2014. The environmental requirements for, and application of environmental regulations (particularly relating to sage grouse) to, the siting process have changed significantly since commencement of the project, making identification of a suitable route for the transmission line more difficult. This has resulted in project delays and increased permitting costs. The completion date of the project is subject to these siting, permitting, and regulatory approval requirements, as well as in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other factors. In light of the delays and siting impediments that have occurred and are expected, Idaho Power is unable to accurately determine an approximate in-service date for the line but expects the in-service date would be in 2020 or beyond.

The permitting-related delays and changing environmental requirements will result in increased project costs, with the magnitude of the increase depending largely on the length of the delay and the line route ultimately approved. The regulatory outcomes associated with the siting process can also affect the ultimate feasibility and cost effectiveness of the project.

The Boardman-to-Hemingway project continues to be Idaho Power's preferred power supply resource project. However, as a component of prudent utility planning, Idaho Power evaluates its resource needs on a regular basis, both inside and outside of the integrated resource planning process required by regulators. This planning process includes a review of projected available power supply resources and demand response programs against projected load demand. Projecting future loads with precision is difficult, and actual loads could exceed estimates, particularly if new large-load customers are added to Idaho Power's system or if customer growth exceeds projections. If Idaho Power believes there will be power supply deficiencies prior to the Boardman-to-Hemingway project's in-service date that cannot be cost-effectively met in other ways (such as through purchased power and use of demand response programs), in order to reliably meet loads Idaho Power would be required to pursue other power supply options in advance of the Boardman-to-Hemingway in-service date. As development of new power supply infrastructure involves substantial lead-time, Idaho Power is currently performing an enhanced review of other power supply resource options.

Idaho Power has expended approximately $55 million on the Boardman-to-Hemingway project through December 31, 2013. Pursuant to the terms of the joint funding arrangements, approximately $27 million of that amount must be reimbursed to Idaho Power by joint permitting participants for expenses Idaho Power incurred, $23 million of which Idaho Power had received as of December 31, 2013. An additional $14 million is subject to reimbursement at a later date from the joint permitting participants, 54-------------------------------------------------------------------------------- Table of Contents assuming their continued participation in the project, for expenses Idaho Power incurred prior to execution of the joint funding arrangements. Idaho Power plans to seek recovery of its share of project costs through the regulatory process.

Memorandum of Understanding, dated January 12, 2012, among Idaho Power, PacifiCorp, and the BPA (2012 MOU): Executed in connection with the BPA's participation in the joint funding agreement for the Boardman-to-Hemingway line, the 2012 MOU provides that the parties will negotiate in good faith the terms of mutually satisfactory definitive agreements that would allow BPA to meet its load service obligations in southeast Idaho. It provides that the parties will explore opportunities to establish eastern Idaho load service from the Hemingway substation in exchange for similar service from the Federal Columbia River Transmission System. The 2012 MOU outlines at least two potential alternatives for further negotiation, including a network service option and an asset ownership rights option on the parties' transmission systems, both of which include BPA participation in the Boardman-to-Hemingway transmission line. Any party may terminate the 2012 MOU at any time, without penalty, and the 2012 MOU automatically expires on December 31, 2014.

Gateway West Transmission Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement (Gateway Funding Agreement) for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $26 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above.

Construction costs are not included in the table above.

The Gateway Funding Agreement outlines the terms under which the parties will jointly own, develop, design, permit, site, and acquire rights-of-way for the Gateway West transmission project. Idaho Power's interest in the Gateway West project applies to four of ten segments involved in the project, referred to as segments 6 (which Idaho Power had previously constructed and is included only for purposes of federal permitting related to the Gateway West project), 8, 9, and 10, comprised of 88, 126, 152, and 34 miles, respectively and each of which is 500-kV. PacifiCorp is designated as the project manager under the agreement.

The Gateway Funding Agreement provides that the project manager may seek to reconfigure portions of the federal permitting project, including segments in which Idaho Power has an interest, subject to certain limitations. Further, PacifiCorp retains the right to remove specified segments from the federal permitting project, including segments in which Idaho Power has an interest, subject to certain limitations specified in the Gateway Funding Agreement.

Each party is responsible for its pro rata share, based on its respective federal and state permitting ownership interest, of the costs incurred under the agreement. Idaho Power's state permitting interest in its segments is 100 percent for segment 6 and 33 percent for each of segments 8, 9, and 10, with a federal permitting interest in the project of 11 percent. The Gateway Funding Agreement provides for the parties to subsequently meet to negotiate the terms and conditions of one or more definitive development and construction agreements for the Gateway West transmission line. The agreement specifies that the parties intend that the terms of any construction agreement would provide that Idaho Power is entitled to one-third of the anticipated bi-directional transmission capacity on segments 8, 9, and 10, and one-third of any total incremental system capacity on those segments, and that PacifiCorp is entitled to the remaining two-thirds interest. A party may withdraw from the federal permitting project, all or a portion of the state permitting project (relating to one or two of segments 8, 9, and 10), or the agreement in its entirety. Upon withdrawal, the withdrawing party forfeits its rights, title, and interest in the agreement and associated tangible and intangible property rights or, if withdrawing from less than all segments, its rights, title, and interest in those segments from which it withdraws.

The BLM released for public comment its final EIS in April 2013 and released its record of decision in November 2013. The record of decision, prepared under the National Environmental Policy Act, identifies the BLM's final decision on the routing for the project. Per the record of decision, the BLM issued right-of-way grants on public land for segments 1 through 7 and 10, but deferred a decision on segments 8 and 9 to resolve routing concerns in those areas. The record of decision provides that a decision on segments 8 and 9 could take up to one year before issuance, while the BLM works with stakeholders.

Jim Bridger Plant Selective Catalytic Reduction Equipment and Related IPUC Filing: Idaho Power and the plant co-owners intend to install selective catalytic reduction (SCR) equipment to reduce nitrogen oxide (NOx) emissions at the Jim Bridger power plant, in order to comply with regional haze rules. The regional haze rules provide for installation and operation of SCR on unit 3 by 2015 and unit 4 by 2016. The rules provide for an equivalent technology for NOx reductions on unit 2 by 2021 and unit 1 by 2022. Idaho Power estimates that the total cost for Idaho Power's share of the upgrades on units 3 and 4 is approximately $118 million, excluding AFUDC. While Idaho Power does not have estimates for the cost to install SCR on 55-------------------------------------------------------------------------------- Table of Contents units 1 and 2, particularly given the technological changes that may occur prior to the installation date on those units, it is possible that the costs will be equal to, or greater than, the costs for units 3 and 4.

In June 2013, Idaho Power filed an application with the IPUC requesting that the IPUC issue a Certificate of Public Convenience and Necessity (CPCN) related to the SCR investments planned for units 3 and 4. Idaho Power's CPCN application requested that the IPUC provide Idaho Power with authorization and a binding commitment to provide rate base treatment for Idaho Power's share of the capital investment in the SCR in the amount of approximately $130 million (including AFUDC), with approximately $63 million authorized for cost recovery on or after January 1, 2016 and approximately $67 million authorized for cost recovery on or after January 1, 2017. By filing the CPCN, Idaho Power intended to provide the IPUC with an opportunity to review the prudence of the investment in SCR prior to Idaho Power's incurring the bulk of the associated expenses. In December 2013, the IPUC issued an order granting the CPCN. However, the IPUC declined to grant Idaho Power's additional request for an early determination of binding ratemaking treatment.

Shoshone Falls Plant Expansion: The Shoshone Falls plant expansion project was included in Idaho Power's 2013 IRP and consists of constructing a new powerhouse, intake structure, penstock, and substation and the installation of a new turbine to increase the nameplate generation capacity of the plant from 12.5 MW to 61.5 MW. Idaho Power estimates the total cost of the generation capacity expansion project to be $106 million. The existing FERC license amendment issued for the plant in 2012 requires the project to be completed by 2017. However, as the project is unlikely to be completed by 2017, Idaho Power anticipates seeking an additional schedule extension from the FERC.

Other Infrastructure Projects: Idaho Power is engaged in a number of other significant projects to reinvest in its system for reliability and other benefits, including a long-term underground cable replacement program, hydroelectric turbine upgrades, and distribution and transmission line construction and upgrades as examples.

Depending on changes in load and project timing Idaho Power may seek to accelerate, scale back, modify, or eliminate projects, or seek alternative projects, to accommodate anticipated resource needs and to help ensure its ability to provide reliable electric service and meet load and transmission capacity obligations. Scaling back or eliminating a project due to regulatory challenges or other factors influencing the feasibility of a project may result in Idaho Power pursuing one or more separate, more costly projects. For instance, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, it may terminate those projects and, as an alternative, develop additional generation facilities within areas where Idaho Power has available transmission capacity. Termination of a project carries with it the potential for a write-off of all or a significant portion of the costs associated with the project, largely dependent on decisions of regulators as to the prudence of project expenditures.

Environmental Regulation Costs: Idaho Power anticipates that it will incur significant expenditures for the installation of environmental controls at its coal plants and for its hydroelectric relicensing efforts. These cost estimates are summarized in Part I - Item 1 - "Business" of this report. The capital portion of these amounts is included in the Capital Requirements table above but do not include costs related to possible changes in current or new 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.

Defined Benefit Pension Plan Contributions Idaho Power contributed $30.0 million, $44.3 million, and $18.5 million to its defined benefit pension plan in 2013, 2012, and 2011, respectively. Federal legislation, signed into law in July 2012, provides a smoothing mechanism applicable to the calculation of plan minimum contributions, and reduces the minimum amounts required to be contributed to the plan in at least the next few years. The legislation's partial funding relief was automatically effective for all contributions beginning in 2013, and Idaho Power chose to adopt the funding relief for its 2012 contributions. Idaho Power's minimum contribution requirement for 2014 is estimated at $1.4 million, though it plans to contribute at least $20 million to the pension plan during 2014 in a continued effort to balance the regulatory collection of these expenditures with the cost of being in an underfunded position. In 2015 and beyond, Idaho Power expects significant contribution obligations under the pension plan. Refer to Note 11 - "Benefit Plans" to the consolidated financial statements included in this report and the section titled "Contractual Obligations" below in this MD&A for information relating to those obligations. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. The primary impact of pension contributions is on timing of cash flows, as cost recovery lags behind the timing of contributions.

56-------------------------------------------------------------------------------- Table of Contents Contractual Obligations The following table presents IDACORP's and Idaho Power's contractual cash obligations for the respective periods in which they are due: Payment Due by Period Total 2014 2015-2016 2017-2018 Thereafter Idaho Power: (millions of dollars) Long-term debt(1) $ 1,619 $ 1 $ 2 $ 121 $ 1,495 Future interest payments(2) 1,331 81 162 161 927 Operating leases(3) 21 1 3 2 15 Purchase obligations: Cogeneration and small power 3,545 170 349 365 2,661 production Fuel supply agreements 228 84 45 19 80 Purchased power & 25 5 10 5 5 transmission(4) Other(5) 227 74 74 22 57 Pension and postretirement 258 9 93 113 43 benefit plans(6) Other long-term liabilities - 1 - - 1 - Idaho Power Total Idaho Power 7,255 425 738 809 5,283 Other 1 1 - - - Total IDACORP $ 7,256 $ 426 $ 738 $ 809 $ 5,283 (1) For additional information, see Note 4 - "Long-Term Debt" to the consolidated financial statements included in this report.

(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.

For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2013.

(3) The operating leases include right-of-way easements. Approximately $1 million of the obligations included have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, has been included in the table for presentation purposes.

(4) Approximately $9 million of the obligations included in purchased power and transmission have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, has been included in the table for presentation purposes.

(5) Approximately $108 million of the amounts in other purchase obligations are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, has been included in the table for presentation purposes. Other purchase obligations also includes Idaho Power's estimated proportionate funding obligation for goods and services under non-fuel purchase agreements at its jointly owned generation facilities and at the jointly owned Bridger Coal Mine. In some instances, Idaho Power is not a direct party to an underlying purchase agreement, but is obligated under the instruments governing the joint ventures to reimburse the co-owner for payments the co-owner makes pursuant to the purchase agreement. Those estimated amounts have been included in the table above.

(6) Idaho Power estimates pension contributions based on actuarial data. As of the date of this report, Idaho Power cannot estimate pension contributions beyond 2018 with any level of precision, and amounts through 2018 are estimates only and are subject to change. For more information on pension and postretirement plans, refer to Note 11 - "Benefit Plans" to the consolidated financial statements included in this report.

Dividends The amount and timing of dividends paid on IDACORP's common stock are within the discretion of IDACORP's board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP's current and long-term financial position and results of operations, capital requirements, rating agency considerations, contractual and regulatory restrictions, 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.

IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive IDACORP's board of directors' dividend decisions.

Notwithstanding the dividend policy adopted by IDACORP's board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the factors above, among others.

57-------------------------------------------------------------------------------- Table of Contents In January 2012, IDACORP's board of directors voted to increase the quarterly dividend from $0.30 to $0.33 per share of IDACORP common stock. In September 2012, IDACORP's board of directors voted to increase the quarterly dividend to $0.38 per share of IDACORP common stock. In September 2013, IDACORP's board of directors voted to increase the quarterly dividend to $0.43 per share of IDACORP common stock.

For additional information relating to IDACORP and Idaho Power dividends, including additional restrictions on IDACORP's and Idaho Power's payment of dividends, see Note 6 - "Common Stock" to the consolidated financial statements included in this report.

Contingencies and Proceedings IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. Certain legal or administrative proceedings to which IDACORP or Idaho Power are parties or are otherwise involved, and certain actual or potential legal claims pertaining to Idaho Power, are described in Note 10 - "Contingencies" to the consolidated financial statements included in this report. Except where noted in Note 10, in many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of potential new regulations, but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

Off-Balance Sheet Arrangements Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental Quality, was $74 million at December 31, 2013, representing IERCo's one-third share of BCC's total reclamation obligation of $221 million.

BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At December 31, 2013, the value of the reclamation trust fund totaled $67 million. During 2013, the reclamation trust fund distributed approximately $28 million for reclamation activity costs associated with the BCC surface mine. BCC periodically 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. Starting 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.

REGULATORY MATTERS Introduction As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC, the OPUC, and the FERC. The IPUC and OPUC 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. 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, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand response programs, seeking to earn a return on investment where permitted by regulators. Idaho Power remains focused on communicating with regulators the necessity of investments to serve its customers, the prudence of the costs incurred, and the importance of a reasonable return on investment for IDACORP's shareholders.

Idaho Power's need for rate relief and the development of rate case plans take into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, among other things, in-service dates of major capital investments and the timing of changes in major revenue and expense items. Idaho Power filed general 58-------------------------------------------------------------------------------- Table of Contents rate cases in Idaho and Oregon during 2011, as well as a single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012. These significant rate cases resulted in the resetting of base rates in both Idaho and Oregon during 2012.

Between general rate cases, Idaho Power relies upon power cost adjustment mechanisms, riders, and other mechanisms to reduce regulatory lag, which refers to the period of time between making an investment or incurring an expense and earning a return and recovering that investment or expense. Management's focus on constructive regulatory outcomes in recent years has been targeted largely at general revenue rate cases and rate mechanisms. Going forward, Idaho Power will continue to assess its need for general rate relief in consideration of the factors described above. Idaho Power will be evaluating its regulatory strategy and options during 2014, and if deemed appropriate could file an application for a general rate change or for the extension of the existing December 2011 regulatory settlement described below. During February 2014, Idaho Power held preliminary discussions with the IPUC Staff regarding such an extension.

Regulatory mechanisms and other regulatory matters, including in many cases their design and their financial impact on IDACORP and Idaho Power, are also discussed in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, which should be read in conjunction with the discussion below.

Idaho and Oregon Significant Regulatory Developments Included below are notable regulatory developments affecting Idaho Power and largely completed during 2011, 2012, and 2013. Refer to Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report for a description of the applicable regulatory mechanism and associated orders of the IPUC and OPUC.

Estimated Annualized Effective Revenue Impact Description Date (millions)(1) 2011 Idaho PCA(2) 6/1/2011 $ (40 ) 2011 Idaho pension expense recovery 6/1/2011 12 2011 Idaho FCA(2) 6/1/2011 3 2011 Oregon annual power cost update (APCU)(2) 6/1/2011 (1 ) 2011 Idaho general rate case settlement 1/1/2012 34 2012 Oregon general rate case settlement 3/1/2012 2 2012 Idaho PCA(2) 6/1/2012 43 Idaho - Boardman power plant cost recovery 6/1/2012 1 Revenue sharing pursuant to January 2010 Idaho 6/1/2012 (27 ) settlement agreement(2) Idaho depreciation rate for non-AMI meters 6/1/2012 (11 ) Idaho depreciation update (other than non-AMI meters 6/1/2012 (1 ) and Boardman plant) 2012 Idaho FCA(2) 6/1/2012 1 2012 Oregon APCU(2) 6/1/2012 2 Idaho - Langley Gulch power plant 7/1/2012 58 Oregon - Langley Gulch power plant 10/1/2012 3 2013 Idaho FCA(2) 6/1/2013 (1 ) 2013 Idaho PCA(2)(3) 6/1/2013 140 2013 Oregon APCU(2) 6/1/2013 3 (1) The annual amount collected in rates is typically not recovered on a linear basis (i.e., 1/12th per month), and is instead recovered in proportion to general business sales volumes.

(2) The rate changes for the Idaho PCA, FCA, and Idaho revenue sharing are applicable only for one-year periods. Similarly, a portion of the rate changes from the Oregon APCU are applicable only for one-year periods.

(3) The 2013 Idaho PCA rates were offset by $7.2 million of Idaho revenue-sharing related to 2012 financial results pursuant to an IPUC order issued in 2012 under regulatory settlement agreements approved in January 2010 and December 2011. The $140.4 million increase in PCA rates includes the reduction in the PCA mechanism component of the revenue sharing amount from $27.1 million for the 2012-2013 PCA to $7.2 million for the 2013-2014 PCA.

Resetting of Idaho Base Rates: In December 2011, the IPUC approved a settlement stipulation in Idaho Power's Idaho general rate case, which provided for a 7.86 percent authorized overall rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdiction base rate revenues. New rates in conformity with the settlement became effective on January 1, 2012. Neither the order nor the settlement stipulation specified an authorized rate of return on equity.

59-------------------------------------------------------------------------------- Table of Contents Idaho Power's Langley Gulch power plant became commercially available on June 29, 2012. On that date the IPUC issued an order approving a $58.1 million, or 6.83 percent, increase in annual Idaho-jurisdiction base rates, effective July 1, 2012, for recovery of Idaho Power's investment in the power plant and associated costs.

In November 2013, Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million in the normalized or "base level" power supply expenses to be used in the determination of the PCA rate that will become effective June 1, 2014. This would remove the Idaho-jurisdiction portion of those expenses eligible for collection via the Idaho PCA mechanism and instead result in Idaho Power collecting that portion in base rates. Approval of the application would result in no net change in the amount collected through base rates and the PCA mechanism in the aggregate. Idaho Power expects, however, that approval of the application would decrease the amount of any base rate increase requested in Idaho Power's next general rate case application filed with the IPUC.

Resetting of Oregon Base Rates: On February 23, 2012, the OPUC approved a settlement stipulation in Idaho Power's Oregon general rate case providing for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation went into effect on March 1, 2012.

On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates, effective October 1, 2012, for inclusion of the Langley Gulch power plant in Idaho Power's Oregon rate base.

Idaho ROE Support Through 2014 from December 2011 Regulatory Settlement Stipulation: In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provided as follows: • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period; • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA; and • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customer rates through an offset in the pension balancing account, which would reduce the amount Idaho Power would seek to collect from customers in future rates.

The December 2011 settlement stipulation provided that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The December 2011 settlement and sharing mechanism followed a similar Idaho settlement and sharing mechanism approved in January 2010, described further in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, which had a substantial impact on IDACORP's and Idaho Power's 2011 results of operations (as discussed in Note 3).

As Idaho Power's 2012 Idaho ROE exceeded 10.5 percent, Idaho Power did not amortize additional ADITC in 2012. For the full year 2012, Idaho Power recorded a $7.2 million provision against current revenues, to be refunded to customers through a reduction in the subsequent year's PCA, and an additional $14.6 million of pension expense, to benefit Idaho customers by reducing the amount of deferred pension expense that may be collected from customers in the future. The $7.2 million rate adjustment was included in the annual PCA rate change that went into effect on June 1, 2013.

Idaho Power's 2013 Idaho ROE also exceeded 10.5 percent. Accordingly, Idaho Power did not amortize additional ADITC in 2013. For the full year 2013, Idaho Power recorded a $7.6 million provision against current revenues, to be refunded to customers through a reduction in the subsequent year's PCA, and an additional $16.5 million of pension expense.

60-------------------------------------------------------------------------------- Table of Contents Change in Deferred (Accrued) Net Power Supply Costs Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual forecasts of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table that follows summarizes the change in deferred net power supply costs over the prior two years.

Idaho Oregon(1) Total Balance at December 31, 2011 $ (13,121 ) $ 8,490 $ (4,631 ) Current period net power supply costs deferred 45,063 1,523 46,586 2011 revenue sharing liability applied to PCA true-up mechanism (27,201 ) - (27,201 ) Prior deferred costs amortized and refunded (recovered) through rates 33,332 (2,178 ) 31,154 SO2 allowance and renewable energy certificate (REC) sales (3,217 ) (160 ) (3,377 ) Interest and other (285 ) 656 371 Balance at December 31, 2012 34,571 8,331 42,902 Current period net power supply costs deferred 67,127 - 67,127 2012 revenue sharing liability applied to PCA true-up mechanism (7,172 ) - (7,172 ) Prior deferred costs amortized and recovered through rates (9,728 ) (2,224 ) (11,952 ) SO2 allowance and renewable energy certificate (REC) sales (522 ) (15 ) (537 ) Interest and other 567 519 1,086 Balance at December 31, 2013 $ 84,843 $ 6,611 $ 91,454 (1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million). Deferrals are amortized sequentially.

Idaho Power's PCA mechanisms in its Idaho and Oregon jurisdictions address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The PCA mechanism and associated financial impacts are described in "Results of Operations" in this MD&A. In May 2013, the IPUC issued an order authorizing a $140.4 million increase in PCA rates, effective for the 2013-2014 PCA collection period commencing June 1, 2013. This significant PCA rate increase was driven by the following: • lower than forecast hydroelectric generation and market energy prices for excess power that Idaho Power sold during the 2012-2013 PCA year (April 1, 2012 through March 31, 2013), and increases in power supply costs associated with lower hydroelectric generation; • forecast lower market energy prices for excess power that Idaho Power sells; • decreased revenue sharing with customers compared to revenue sharing included in the prior PCA rates; and • forecast below-average hydroelectric generating conditions during the 2013-2014 PCA year (April 1, 2013 through March 31, 2014).

Idaho Power's currently approved normalized level of net power supply expenses included in Idaho jurisdictional base rates were established in 2010. Since 2010, many of the individual cost and revenue components of these "base level" net power supply expenses have changed significantly and permanently. These ongoing and permanent costs are currently being recovered through the Idaho PCA annually. The primary factors contributing to the increase in net power supply expenses were increased energy purchases pursuant to PURPA, lower surplus energy sales revenue resulting from lower energy market prices, and the elimination of anticipated offsetting revenues from the Hoku electric service agreement. As noted above, Idaho Power filed an application with the IPUC requesting an increase of approximately $106 million in the normalized or "base level" power supply expense to be used in the determination of the PCA rate that will become effective June 1, 2014. This would remove the Idaho-jurisdiction portion of those expenses eligible for collection via the Idaho PCA mechanism and instead result in Idaho Power collecting that portion in base rates.

61-------------------------------------------------------------------------------- Table of Contents Transmission Coordination and FERC Order 1000 The FERC has encouraged increased coordination intended to capture power transmission efficiencies that might otherwise be gained through the formation of a regional transmission organization or independent system operator. While it has not mandated formation of such an organization, the FERC has issued orders and made public statements indicating its support for the development and formation of independent organizations, including those intended to implement a number of regional transmission planning coordination requirements.

In 2011, FERC issued Order 1000, which reforms its electric transmission planning and cost allocation requirements for public utility transmission providers. This final rule requires that transmission providers develop and implement regional and interregional planning and cost allocation processes.

These processes are intended to, among other things, improve coordination between neighboring transmission providers and regions and to determine if there are more efficient or cost effective solutions to transmission needs. Order 1000 requires development of cost allocation processes that would seek to allocate costs to beneficiaries of a transmission project in a manner that is roughly commensurate with benefits. These procedural changes will require increased time and participation on a regional and interregional level by Idaho Power. The cost allocation processes of a regional transmission facility may assign some costs to other beneficiaries and may result in a change in costs attributable to Idaho Power and its customers.

Another significant change is the removal of the federal right of first refusal provision contained in tariffs or agreements with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation. Incumbent public utility transmission providers no longer have a federal right of first refusal to build, own, and operate large-scale regional transmission projects when they seek regional cost allocation. Idaho Power has filed its tariff revisions with the FERC for the regional and interregional portions of Order 1000 requirements. On May 17, 2013, the FERC issued an order accepting, with some modifications, Idaho Power's regional filing, subject to Idaho Power submitting additional compliance filings with the FERC, which Idaho Power made in September and October 2013. As of the date of this report, Idaho Power is unable to determine what impacts this order may have on its future electric transmission service costs or charges.

FERC Compliance Programs The FERC has approved an extensive number of reliability standards developed by the NERC and the Western Electricity Coordinating Council (WECC), including critical infrastructure protection (CIP) standards and regional standard variations. As part of its compliance program, Idaho Power periodically reviews its operations for compliance with FERC rules, orders, and standards and self-reports compliance issues to the FERC and the WECC. Recent reports Idaho Power has submitted to the FERC have generally focused on Standards of Conduct and Idaho Power's FERC OATT. Consistent with prior years, during 2013 Idaho Power self-reported to the FERC and received notices of alleged violations from the FERC and the WECC. Idaho Power has also received notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power. Consistent with its historical practice, Idaho Power is working with the FERC and the WECC to resolve alleged violations and items it self-reported to the FERC and the WECC. Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but based on the nature of the potential violations Idaho Power does not expect any material adverse effect from currently alleged violations on its financial position, results of operations, or cash flows. Idaho Power plans to continue its efforts to reduce potential violations through its compliance program and its approach of self-reporting compliance issues to, and working with, the FERC and the WECC.

One item currently undergoing review is a pricing-related issue associated with Idaho Power's triennial market power analysis filed with the FERC, the filing of which is a requirement of Idaho Power's market-based rate tariff. Resolution of that item, which is premised on whether certain transmission rates to eligible customers should have been calculated under a cost-based or market-based approach, could result in Idaho Power issuing refunds to eligible customers.

However, Idaho Power does not expect the aggregate amount of any such refunds would be material to its financial condition or results of operations.

Relicensing of Hydroelectric Projects Overview: Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses have a term of 30 to 50 years depending on the size, complexity, and cost of the project. The expiration dates for the FERC licenses for each of the facilities are included in Part I - Item 2 - "Properties" in this report. Costs for the relicensing of Idaho Power's hydroelectric projects 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 $180 million for the HCC, Idaho Power's largest hydroelectric complex and a 62-------------------------------------------------------------------------------- Table of Contents major relicensing effort, were included in construction work in progress at December 31, 2013. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5 million annually ($10.7 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project. Collecting these amounts now will reduce the amount collected in the future once the HCC relicensing costs are approved for recovery in base rates. As of December 31, 2013, Idaho Power's regulatory liability for collection of AFUDC relating to the HCC was $59.0 million, including $20.5 million for the income tax gross up and $6.6 million of carrying charges on the balance. In addition to the discussion below, see "Environmental Matters" in this MD&A for a discussion of environmental compliance under FERC licenses for Idaho Power's hydroelectric generating plants.

Hells Canyon Complex: The HCC, located on the Snake River where it forms the border between Idaho and Oregon, provides approximately 68 percent of Idaho Power's hydroelectric generating nameplate capacity and 32 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application with the FERC for a new license in anticipation of the July 2005 expiration of the then-existing license. Since the expiration of that license, Idaho Power has been operating the project under annual licenses issued by the FERC. In December 2004, Idaho Power and eleven other parties, including National Marine Fisheries Service (NMFS) and U.S. Fish and Wildlife Service (USFWS), involved in the HCC relicensing process entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on Endangered Species Act (ESA) listed species pending the relicensing of the project. 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 ESA, which remain unresolved.

In connection with its relicensing efforts, 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. Section 401 of the CWA requires that a state either approve or deny a Section 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 CWA. 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 with the states to identify measures that will provide reasonable assurance that discharges from the HCC will adequately address applicable water quality standards.

In September 2007, in connection with the issuance of its final EIS, the FERC notified the NMFS and the USFWS of its determination that the licensing of the HCC was likely to adversely affect ESA-listed species, including the bull trout and fall Chinook salmon and steelhead, 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.

Idaho Power continues to work with Idaho and Oregon in the development of measures to provide reasonable assurance that any discharges from the HCC will comply with applicable state water quality standards so that appropriate water quality certifications can be issued for the project, and continues to cooperate with the USFWS, NMFS, and the FERC in an effort to address ESA concerns.

Measures that have been considered to address water quality standards include installation of aerated runners in the Brownlee project (part of the HCC) turbines, modification of spillways at Brownlee and Hells Canyon to address total dissolved gas issues, and upstream watershed improvements or the installation of a temperature control structure to address water temperatures during a small portion of the year. These water quality measures could add substantially to project costs. For instance, in its August 2007 final EIS the FERC's proposed protection, mitigation, and enhancement measures had an estimated cost of approximately $15 million per year, excluding costs for measures associated with the Section 401 water quality certification because they had not been defined at that time. Idaho Power continues to work with the Oregon and Idaho Departments of Environmental Quality on the water quality certification issue and the water quality measures that will be required to obtain 401 certification. As of the date of this report, Idaho Power is unable to predict the timing of issuance by the FERC of any license order or the ultimate capital investment and ongoing operating and maintenance costs Idaho Power will incur in complying with any new license.

Swan Falls Project: In September 2012, the FERC issued to Idaho Power a 30-year license for continued operation of the Swan Falls hydroelectric project. Idaho Power believes that operational changes associated with the new license for the project 63-------------------------------------------------------------------------------- Table of Contents will be modest and that the capital investments it will be required to make under the terms of the license will be within the range Idaho Power expected at the time of submission of its application for the license.

Shoshone Falls Plant Expansion: On July 1, 2010, the FERC amended the license for the Shoshone Falls project to expand its nameplate generating capacity from approximately 12.5 MW to approximately 61.5 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. On May 1, 2012, FERC granted Idaho Power a two-year schedule extension, through July 2017, to complete construction of the expansion. Idaho Power does not expect that it would complete the generation capacity expansion project prior to 2017, and thus anticipates seeking an additional schedule extension from the FERC. Idaho Power's determination to proceed with the expansion project remains subject to the outcome of additional cost studies and analysis and the results of further engineering and design work, and further analysis of Idaho Power's supply-side resource needs. If Idaho Power ultimately determines to move forward with the full project, Idaho Power may seek to obtain regulatory support from the IPUC and OPUC prior to commencement of construction to mitigate in part the regulatory cost-recovery risk associated with the project.

Renewable Energy Standards and Contracts Renewable Portfolio Standards: Numerous proponents have introduced legislation in the U.S. Congress that would require electric utilities to obtain a specified percentage of their electricity from renewable sources, commonly referred to as a "renewable portfolio standard" or "RPS." However, as of the date of this report no federal or State of Idaho RPS is in effect. Idaho Power will be required to comply with a 10-percent RPS in Oregon beginning in 2025, and Idaho Power expects to meet this requirement with renewable energy certificates (RECs) obtained from the purchase of power from the Elkhorn Valley wind project. Idaho Power continues to monitor proposed federal RPS legislation and the possibility of additional state RPS legislation.

Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to customers their share (shared 95% with customers in the Idaho jurisdiction) of those proceeds through the PCA. For the years ended December 31, 2013 and 2012, Idaho Power's REC sales totaled $0.6 million and $3.5 million, respectively. Idaho Power has sold all of its 2012 and earlier vintage RECs. Idaho Power has sold a portion of its 2013 RECs and intends to continue selling its 2013 and later RECs as they are generated and become available for sale.

Were Idaho Power to be subject to additional RPS legislation, it may cease in full or in part the sale of RECs it receives, seek to obtain RECs from additional projects, generate RECs from any REC-generating facilities it may own, or purchase RECs in the market. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects. However, an order issued by the IPUC in December 2012, described below, provides that Idaho Power will own a portion of the RECs generated by some future PURPA projects. The required purchase of additional RECs to meet RPS requirements would increase Idaho Power's costs, which Idaho Power expects would be wholly or largely passed on to customers through rates and the PCA mechanisms.

Renewable Energy Contracts and PURPA: Idaho Power purchases wind power from both cogeneration and small power production (CSPP) and non-CSPP facilities, including its largest non-CSPP wind power project-the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of December 31, 2013, Idaho Power had contracts to purchase energy from on-line CSPP wind power projects with a combined nameplate rating of 577 MW. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other CSPP and non-CSPP renewable generation sources, such as biomass, solar, small hydroelectric projects, and two geothermal projects. As of December 31, 2013, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the table below.

Number of Nameplate CSPP Capacity Status Contracts (MW) On-line as of December 31, 2013 102 774 Contracted and projected to come on-line by year-end 2016 6 48 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 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 it does not need at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms, and thus the primary impact of PURPA agreements is on customer rates.

64-------------------------------------------------------------------------------- Table of Contents Idaho Power has been involved in a number of PURPA-related proceedings at the IPUC, OPUC, and the FERC, and has previously intervened in proceedings between the IPUC and the FERC. While some of those proceedings are ongoing and a number of decisions are being challenged, certain notable developments have occurred in recent years. In June 2011, the IPUC issued an order providing for a 100 kW eligibility cap for published avoided cost rates for wind and solar PURPA projects. In December 2012, the IPUC issued an order providing that for projects not eligible for published avoided cost rates, the price used for power purchase determinations would be updated annually based on updated natural gas prices and Idaho Power's updated load forecast. The IPUC also determined that RECs will be owned by the PURPA project developer for projects eligible for published avoided cost rates, and apportioned equally between the project developer and Idaho Power for other projects. The IPUC's order also provided that new projects will be paid for capacity based on the project's ability to deliver during peak hours and when Idaho Power's long-range plan shows the company is capacity deficient.

Additionally, in December 2013 the IPUC and the FERC signed a memorandum of agreement dismissing claims brought in a U.S. District Court in Idaho relating to the interpretation and enforcement of PURPA as it pertained to several power purchase agreements with wind power developers. The memorandum of agreement reflects the principle that PURPA establishes a program of cooperative federalism, with FERC establishing regulations and states implementing them in a manner that accommodates local conditions.

ENVIRONMENTAL MATTERS Overview Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment, including the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act, and the ESA, among other laws. Current and pending environmental legislation relates to, among other issues, climate change, greenhouse gas, mercury and other emissions, air quality, hazardous wastes, polychlorinated biphenyls, and threatened and endangered species. These laws are administered by a number of federal, state, and local agencies. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to regulators to levy substantial penalties for noncompliance, injunctive relief, and other sanctions. Idaho Power's three coal-fired power plants and three natural gas-fired combustion turbine power plants are subject to many of these regulations. Idaho Power's 17 hydroelectric projects are also subject to a number of water discharge standards and other environmental requirements.

Compliance with current and future environmental laws and regulations may: • increase the operating costs of generating plants; • increase the construction costs and lead time for new facilities; • require the modification of existing generating plants, which could result in additional costs; • require the curtailment or shut-down of existing generating plants; or • reduce the output from current generating facilities.

Current and future environmental laws and regulations will increase the cost of operating coal-fired power plants and constructing new facilities, in large part through the installation of additional pollution control devices at existing generating plants, and could result in Idaho Power discontinuing the operation of one or more coal-fired plants if operation becomes uneconomical. These regulations could, in turn, affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements and plant shut-downs cannot be fully recovered in rates on a timely basis. Part I - "Business - Environmental Regulation and Costs" in this report includes a summary of Idaho Power's expected capital and operating expenditures for environmental matters during the period from 2014 to 2016. Given the uncertainty of future environmental regulations and technological advances, Idaho Power is unable to predict its environmental-related expenditures beyond 2016, though they could be substantial.

In connection with its IRP process, Idaho Power conducted cost studies and scenario analysis to assess the potential future investments necessary for the continued operation of the Jim Bridger and North Valmy coal generation facilities, in light of the body of environmental laws and regulations impacting the cost of operating those plants. The results of that study are discussed in Part I, Item 1 - "Business - Utility Operations - Environmental Regulation and Costs." Idaho Power will continue to monitor environmental requirements to assess whether environmental control upgrades remain economically appropriate.

65-------------------------------------------------------------------------------- Table of Contents Endangered Species and Fisheries Matters Overview: The listing of a species of fish, wildlife, or plants as threatened or endangered under the ESA may have an adverse impact on Idaho Power's ability to construct generation, transmission, or distribution facilities or relicense or operate its hydroelectric projects. When a species is added to the federal list of threatened and endangered species, it is protected from "take" and from being transported, traded, or sold. The term "take" under the ESA is interpreted to include "harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct." Section 7 of the ESA also provides that each federal agency shall ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the destruction or adverse modification of its critical habitat.

The construction of generation, transmission, or distribution facilities and the licensing of Idaho Power's hydroelectric projects can be federally authorized actions that fall under Section 7 of the ESA. There are a number of threatened or endangered species within Idaho Power's service area and within or near proposed transmission line routes. Further, there are a number of ESA-listed fish and other aquatic species located in waterways in which Idaho Power has hydroelectric facilities, including fall Chinook salmon, bull trout, Bliss Rapids snail, and Snake River physa snail. To date, efforts to protect these and other listed species have not significantly affected generation levels at any of Idaho Power's hydroelectric facilities. However, the ongoing relicensing of the HCC presents endangered species and fisheries issues that may require generation or other operational adjustments. These adjustments may reduce the generation output or operating costs (and hence the economics) of the plants, potentially causing Idaho Power to rely on more expensive sources for power generation or market purchases.

ESA Issues Related to Specific Species: Slickspot Peppergrass: This southwestern Idaho plant species was listed as threatened by the USFWS in 2009. In May 2011, the USFWS issued a proposed rule to designate critical habitat for the slickspot peppergrass and proposed to designate approximately 58,000 acres of critical habitat in four southeast Idaho counties. Approximately 98 percent of the plant species is located on federal land owned by the BLM and the U.S. Department of Defense. The BLM is currently treating the species as a proposed species under ESA and will confer with the USFWS until a final decision is made. Parts of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines will cross BLM land upon which this species is located. The listing of the slickspot peppergrass will require that Idaho Power, as one of the project developers, engage in an ESA Section 7 consultation with the USFWS, which will increase the cost of the transmission projects and potentially delay the receipt of a permit for construction.

Greater Sage Grouse: The greater sage grouse is considered a "candidate species" under the ESA, which allows land management agencies to implement additional conservation measures. In March 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. On February 2, 2012, a federal district court in Idaho issued an order denying a request to expedite the listing of the greater sage grouse under the ESA. As a result, the USFWS has until 2015 to make a final listing determination under the ESA. On February 6, 2012, the same court issued an order holding that the BLM had violated the National Environmental Policy Act and other federal laws in connection with the granting of livestock grazing permit renewals in sage grouse habitat. Due to the presence of sage grouse in the vicinity of the Boardman-to-Hemingway and Gateway West 500-kV transmission lines, siting of these projects has required more extensive, costly, and time consuming evaluation, permitting, and engineering.

In the event the USFWS lists the greater sage grouse as threatened or endangered, federal agencies that may authorize rights-of-way to Idaho Power, as one of the project developers, would be required to conduct a Section 7 consultation under the ESA for these transmission projects. Any required additional conservation measures may impact the timing for siting, permitting, and constructing the Boardman-to-Hemingway and Gateway West transmission lines and other projects.

Washington Ground Squirrel: The Washington ground squirrel is considered a "candidate species" under the ESA. There are multiple records of Washington ground squirrels within or near portions of the proposed Boardman-to-Hemingway transmission line project. If this species is listed under the ESA, the BLM would be required to conduct a Section 7 consultation under the ESA for the Boardman-to-Hemingway project. If additional surveys are required, or if additional conservation and mitigation measures need to be developed, the overall timing of the permitting and construction, and the cost, of the Boardman-to-Hemingway project may be adversely affected.

ESA Issues Related to Specific Projects: Hells Canyon Relicensing Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the NMFS and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has yet to be initiated and the NMFS and the USFWS continue to gather and consider information relative to the 66-------------------------------------------------------------------------------- Table of Contents effects of relicensing on relevant ESA listed species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. In December 2004, Idaho Power and eleven other parties, including NMFS and the USFWS, entered into an interim agreement that addresses the effects of the ongoing operations of the HCC on ESA listed species pending the relicensing of the project. At the conclusion of formal consultation and with the issuance of biological opinions by the NMFS and the USFWS and an operating license by the FERC, Idaho Power may be required to implement additional measures or further modify or adjust operations to comply with Section 7 of the ESA. The issuance of a final biological opinion during 2014 is unlikely.

Bliss and Lower Salmon Falls Projects: As part of a settlement agreement for the current FERC hydroelectric license, Idaho Power finalized a snail protection plan for the Bliss and Lower Salmon Falls projects in cooperation with the USFWS. Idaho Power filed applications with the FERC to amend the licenses for the projects to help maintain operating flexibility at both projects for the remainder of their licenses. In March 2013, the FERC issued an order approving Idaho Power's application to return to load-following operations at the Bliss and Lower Salmon Falls projects for the duration of the new license period through 2034. Idaho Power had been operating these projects as run-of-river facilities since the licenses were issued in 2004, pending the results of a settlement agreement driven by an ESA snail study that was conducted for a period of six years. The order also approved a snail protection plan, and required Idaho Power to investigate opportunities to acquire and manage 64.5 acres of riparian habitat to mitigate the potential impact on land of load-following operations below the projects.

Swan Falls Project: In August 2010, the FERC issued a final EIS in connection with the relicensing of the Swan Falls Project. The Snake River physa snail was found in the area during the EIS review. While the applicable biological opinion includes a provision for the incidental take of the snail, Idaho Power is required to study the status of the Snake River physa snail and its habitat within and downstream of the project area for the term of the new license.

Boardman-to-Hemingway and Gateway West Transmission Projects: As noted above, the existence of the slickspot peppergrass, greater sage grouse, and Washington ground squirrel within or near the proposed routes for these projects is impacting, and Idaho Power expects it to continue to impact, the cost and timing of permitting and construction of the projects.

Climate Change and the Regulation of Greenhouse Gas (GHG) Emissions Overview: Long-term climate change could significantly affect Idaho Power's business in a variety of ways, including: • changes in temperature and precipitation could affect customer demand and energy loads; • extreme weather events could increase service interruptions, outages, maintenance costs, and the need for additional backup systems, and can affect the supply of, and demand for, electricity and natural gas, which may impact the price of energy commodities; • 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 plants and operations, including restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources; and • consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact usage of existing generation sources and require significant investment in new generation and transmission infrastructure.

Some recent initiatives regarding GHG emissions contemplate market-based compliance programs, such as cap-and-trade programs or emission offsets.

However, 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 many 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 coal-fired units. Due in part to the uncertainty of future GHG regulations, in its 2011 and 2013 IRPs Idaho Power did not include any new conventional coal resources in its resource portfolios.

A variety of factors contribute to the financial, regulatory, and logistical uncertainties related to GHG reductions, including the specific GHG emissions limits, the timing of implementation of these limits, 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.

67-------------------------------------------------------------------------------- Table of Contents Accordingly, Idaho Power cannot predict the effect on its results of operations, financial position, or cash flows of any GHG emission or other global climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. A more detailed discussion of legislative and regulatory developments related to climate change follows.

National and International GHG Initiatives: There is concern both nationally and internationally about climate change and the possible contribution of GHG emissions to climate change. In support of international efforts to reduce GHG emissions, in January 2010 the Obama Administration pledged to cut GHG emissions in the United States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. Other communications from the Obama Administration have proposed the adoption of a clean energy standard in the U.S., calling for 80 percent of American energy to come from clean sources by 2035. Further, climate change regulation has been a recent priority of the U.S. Congress. In prior legislative sessions, legislation in both the U.S. House and Senate was introduced to enact a comprehensive climate change program, but these attempts were unsuccessful. At the same time, legislation has also been introduced seeking to amend the CAA to prohibit the U.S. Environmental Protection Agency (EPA) from promulgating regulations on the emissions of GHGs to address climate change and excluding GHGs from the definition of an "air pollutant" for purposes of addressing climate change. Neither areas of focus have culminated in legislation and have led to greater uncertainty as to the direction of GHG regulation.

At the same time, the EPA has become increasingly active in the regulation of GHGs. The EPA's endangerment finding in 2009 that GHGs threaten public health and welfare resulted in the enactment of a series of EPA regulations to address GHG emissions. The EPA has issued final rules regulating GHG emissions under the New Source Review (NSR)/Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs under the CAA. Specifically, in May 2010 the EPA issued the "Tailoring Rule," which set thresholds for GHG emissions that define when permits are required for new and existing industrial facilities. The final rule "tailors" the requirements of these CAA permitting programs to limit which facilities will be required to obtain PSD and Title V permits. Additionally, in December 2010 the EPA issued a series of final regulations for GHG emissions designed to ensure that industrial facilities can obtain CAA permits for GHG emissions, and that facilities emitting GHGs at levels below those established in the Tailoring Rule do not need federal CAA permits. The first phase of the rules took effect in January 2011 and required 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, Title V permit renewals or modifications for existing major sources must include applicable requirements relating to GHGs. While the rules are complex, Idaho Power believes that its owned and co-owned generation plants are, as of the date of this report, in compliance with the new GHG Tailoring Rules.

In addition, in April 2012 the EPA proposed New Source Performance Standards (NSPS) regulating CO2 emissions from new electric generating units (EGUs) under the CAA. On June 25, 2013, President Obama issued a Presidential Memorandum entitled "Power Sector Carbon Pollution Standards," in which he directed the EPA to (a) issue a revised proposed rule for setting carbon emission standards for new EGUs, and (b) issue proposed standards, regulations, or guidelines under the CAA to address carbon pollution from modified, reconstructed, and existing power plants, to be finalized by June 2015. As required by the Presidential Memorandum, on September 20, 2013, the EPA re-proposed its NSPS rule regulating CO2 emissions from new gas- and coal-fired power plants under the CAA, and formally published the rule for public comment on January 8, 2014. The new proposal replaces the EPA's prior proposal from April 2012. The proposed rule establishes different standards for new natural gas-fired combustion turbines based on the size of the plant -- 1,000 pounds of CO2/MWh for large natural gas-fired turbines (greater than 850 mmBtu/hr) and 1,100 pounds of CO2/MWh for smaller natural gas-fired turbines (less than 850 mmBtu/hr). New coal-fired units would be required to meet a standard of 1,100 pounds of CO2/MWh over a 12 month operating period, or a range of 1,000 to 1,050 pounds of CO2/MWh for a seven-year operating period. The proposed standard for coal-fired units is intended to take into consideration current technologies available for carbon capture and sequestration and efforts to implement that technology.

In its 2013 IRP, Idaho Power did not include any new coal-fired power plants in any of its resource portfolios for the 20-year planning period. It did, however, include new natural gas-fired power plants in its various portfolios, and thus the EPA's proposed rule would impact the allowable CO2 emissions from those facilities. Idaho Power believes its future natural gas-fired power plants would be capable of complying with the EPA's re-proposed NSPS for new power plants.

Idaho Power, however, could incur additional costs for environmental controls at its existing EGUs depending on the standards the EPA issues for modified, reconstructed, and existing power plants.

State and Regional GHG Initiatives: On a regional level, there are a number of initiatives, including the Western Regional Climate Action Initiative, considering market-based mechanisms to reduce GHG emissions. Separately, in August 2007 the Oregon legislature enacted legislation setting goals of reducing GHG levels to 10 percent below 1990 levels by 2020 and at least 75 percent below 1990 levels by 2050. Oregon imposes GHG emission reporting requirements on facilities emitting 2,500 68-------------------------------------------------------------------------------- Table of Contents metric tons or more of CO2 equivalent annually. The Boardman coal-fired power plant located in Oregon, in which Idaho Power is a 10-percent owner, is subject to and in compliance with Oregon's GHG reporting requirements.

The State of Idaho has not passed legislation specifically regulating GHGs, but in May 2007 Governor Otter issued Executive Order 2007-05, which directed the Idaho Department of Environmental Quality to work with the state government to implement GHG reductions within each agency, complete a statewide emissions inventory, and provide recommendations to the Governor, among other tasks.

Wyoming and Nevada similarly have not enacted legislation to regulate GHG emissions and do not have a reporting requirement, but are members of the Climate Registry, a national, voluntary GHG emission reporting system. The Climate Registry is a collaboration aimed at developing and managing a common GHG emission reporting system across states, provinces, and tribes to track GHG emissions nationally. All states for which Idaho Power has traditional fuel generating plants (i.e. Idaho, Oregon, Wyoming, and Nevada) are members of the Climate Registry.

Idaho Power's Voluntary GHG Reduction Initiatives: Despite the current absence of a national mandatory GHG reduction program, Idaho Power is engaged in voluntary GHG emissions intensity reduction efforts. Also, Idaho Power has voluntarily 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 emissions intensity (lbs/MWh) from its generation facilities as submitted to the Carbon Disclosure Project was 871 lbs/MWh, 677 lbs/MWh, 1,060 lbs/MWh, 1,004 lbs/MWh, 1,097 lbs/MWh, and 1,150 lbs/MWh for 2012, 2011, 2010, 2009, 2008, and 2007, respectively.

In 2011, Idaho Power and Ida-West together ranked as the 24th lowest emitter of CO2 per MWh produced and the 28th lowest emitter of CO2 by tons of emissions among the nation's 100 largest electricity producers, according to the May 2013 Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States, based on 2011 generation and emissions data. This report is the product of a collaborative effort among Bank of America, Entergy, Exelon, Pacific Gas & Electric Company, Public Service Enterprise Group, Tenaska, Ceres, and the Natural Resources Defense Council. According to the report, out of the 100 companies named, Idaho Power and Ida-West together ranked as the 48th largest power producer based on fossil fuel, nuclear, and renewable energy facility total electricity generation.

Public Nuisance-Related Suits for GHGs: In June 2011, the U.S. Supreme Court held that federal courts do not have jurisdiction to hear federal common law nuisance claims relating to GHG emissions because the legal authority to regulate GHGs has been delegated by Congress to the EPA, not to the federal courts. The Court did not address, however, whether state common law nuisance claims would also be barred by the federal CAA. Accordingly, the Supreme Court's decision did not completely eliminate the potential for future nuisance-related suits for GHG emissions.

Clean Air Act Matters Overview: In addition to the CAA developments related to GHG emissions described above, several other regulatory programs developed under the CAA impact Idaho Power. These include the final Mercury and Air Toxics Standards (MATS), National Ambient Air Quality Standards (NAAQS), NSR/PSD Rules, and the Regional Haze Rule.

Final MATS Implementation: Several regulatory programs developed under the CAA impact Idaho Power. The CAA requires the EPA to develop industry-based standards to control emissions of hazardous air pollutants (HAPs). In February 2012, the EPA issued the final MATS rule to control emissions of mercury and other HAPs from coal- and oil-fired EGUs under the CAA. Additionally, on March 28, 2013, the EPA issued a notice by which it finalized its MATS with regard to all pending issues except for the shutdown and startup of plants, in light of a number of requests for reconsideration that were filed by the electric utility industry. The notice revised the mercury emissions standard originally proposed in the February 2012 rule to make the mercury emission standard less stringent.

The final rule took effect in April 2013. The compliance deadline for the new MATS has been established as April 2015. While the new MATS only applies to EGUs constructed in the future, and as a result Idaho Power does not expect the new standards to impact its existing generation facilities, the new MATS would impact the nature and extent of environmental controls to be installed on new EGUs, and thus would likely increase the cost of constructing new EGUs.

National Ambient Air Quality Standards: The CAA requires the EPA to set ambient air quality standards for six "criteria" pollutants considered harmful to public health and the environment. These six pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. States are then required to develop emission reduction strategies through State Implementation Plans, or SIPs, based on attainment of these ambient air quality standards.

Recent developments related to three of these pollutants - PM2.5, NOx, and Sulfur Dioxide (SO2) are relevant to Idaho Power.

69-------------------------------------------------------------------------------- Table of Contents • Particular Matter (PM2.5). In 1997, the EPA adopted NAAQS for fine particulate matter of less than 2.5 micrometers in diameter (PM2.5 standard), setting an annual limit of 15 micrograms per cubic meter (µg/m3), calculated as a three-year average. In 2006, the EPA adopted a 24-hour NAAQS for PM2.5. of 35 µg/m3. All of the counties in Idaho, Nevada, Oregon, and Wyoming in which Idaho Power's power plants are located have been designated as "attainment" with these PM2.5 standards.

However, on December 14, 2012, the EPA released final revisions to the PM2.5 NAAQS. The revised annual standard is 12 µg/m3, calculated as a three-year average. The EPA retained the existing 24-hour standard of 35 µg/m3. Now that the PM2.5 NAAQS has been finalized, states will make recommendations to the EPA regarding designations of attainment or non-attainment. States also will be required to review, modify, and supplement their state implementation plans (SIPs), which are plans required under the CAA to meet various air quality standards and must be approved by the EPA. Supplementation of a state's SIP could require the installation of additional controls and requirements for Idaho Power's coal-fired generation plants, depending on the level ultimately finalized.

The revised NAAQS would also have an impact on the applicable air permitting requirements for new and modified facilities. The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having until 2020 to comply with the standards.

• NOx. In 2010, the EPA adopted a new NAAQS for NOx at a level of 100 parts per billion averaged over a 1-hour period. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as "unclassifiable/attainment" for NOx. The EPA indicated it will review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NOx. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants. As the designations have not yet been finalized, as of the date of this report Idaho Power is unable to predict the impact of the NAAQS for NOx on its operations. However, the costs of installation and implementation of any additional pollution reduction technology could be substantial.

• SO2. In 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. In 2011, the states of Idaho, Nevada, Oregon, and Wyoming sent letters to the EPA recommending that all counties in these states be classified as "unclassifiable" under the new one-hour SO2 NAAQS because of a lack of definitive monitoring and modeling data. In February 2013, the EPA issued letters to the states of Idaho and Oregon, finding that the most recent air quality data for those states showed no violations of the 2010 SO2 standard. As a result, the EPA is waiting to propose designation actions for those states, and is likely to proceed with designation actions once additional data is gathered. Idaho Power expects that designations for Nevada and Wyoming will also be addressed in a separate future action.

Because the EPA has not yet completed the designation of 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, though it does expect at least some increases in capital and operating costs from the standards.

Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any "Class I" (wilderness) areas. This includes all four units at the Jim Bridger and the Boardman coal-fired plants.

Jim Bridger Plant: In December 2009, the Wyoming Department of Environmental Quality (WDEQ) issued a RH BART permit to PacifiCorp as the operator of the Jim Bridger plant. As part of the WDEQ's long term strategy for regional haze, the permit requires that PacifiCorp install SCR equipment 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 unit 1 by 2022 and unit 2 by 2021. In November 2010, PacifiCorp and the WDEQ signed a settlement agreement under which PacifiCorp agreed to the timing and nature of the controls. The settlement agreement was conditioned on the EPA ultimately approving those portions of the Wyoming Regional Haze SIP that are consistent with the terms of the settlement agreement. On January 10, 2014, the EPA approved Wyoming's Regional Haze SIP as to the Jim Bridger plant, with the NOx control compliance dates set forth in the settlement agreement.

Boardman Plant: Following the introduction of various plans and an extensive public process, in December 2010 the Oregon Environmental Quality Commission (OEQC) approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The rules implementing the plan require the installation of a number of emissions controls and repeal the OEQC's 2009 BART rule, which would have allowed continued operation of the Boardman plant through at least 2040 with installation of a more extensive suite of emissions controls. The estimated combined total capital cost of the required 70-------------------------------------------------------------------------------- Table of Contents controls under the plan approved by the OEQC for controlling mercury, NOx and SO2 is approximately $57 million. Idaho Power is a 10 percent owner of the Boardman plant, and thus Idaho Power's estimated share of the capital cost is approximately $6 million, which is in addition to normal capital expenditures and maintenance costs. As of December 31, 2013, Idaho Power had incurred charges of $5.7 million, including AFUDC, of its total estimated share of the capital cost for the new controls.

New Source Review / Prevention of Significant Deterioration: NSR/PSD is a preconstruction permitting program that requires a stationary source of air pollution to obtain a permit before beginning construction. The purpose of the program is to ensure that air quality is not significantly degraded by the addition of new and modified facilities, industrial boilers, and power plants.

Under current NSR provisions of the CAA, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory equivalent before beginning the construction of a stationary source that will emit regulated pollutants, or before modifying an existing stationary source that will increase its emission levels. 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 under 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. As part of an industry-wide assessment of compliance with NSR and NSPS, EPA has sought information from a number of utilities regarding their coal-fired generating facilities. In 2003, the EPA sent information requests pursuant to the CAA to the Jim Bridger plant, seeking information relevant to NSR and NSPS compliance. Additional requests were received by the Valmy plant in 2009 and the Boardman plant in 2008, with a follow up request for information in 2009. In September 2010, the EPA issued a Notice of Violation to Portland General Electric Company, the operator of the Boardman plant, alleging that Portland General Electric Company violated the NSPS under Section 111 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. To date, the EPA has not taken action on the Notice of Violation, and a related private lawsuit under the CAA was settled in 2011.

Potential Regulation of Coal Combustion Residuals (CCRs) The Resource Conservation and Recovery Act (RCRA) is a federal statute regulating the generation, treatment, storage, and disposal of solid and hazardous wastes. 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 response, in June 2010 the EPA proposed regulations governing the disposal and management of CCRs, which are regulated under the RCRA. The EPA requested comments on two options for regulating CCRs. The first option 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 requirements. To date the EPA has not issued final regulations. Both of the EPA's proposed options represent a shift toward more comprehensive and potentially more expensive requirements for CCR management and disposal. 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, operations, or cash flows. However, the financial and operational consequences cannot be determined until final legislation is passed or regulations are issued.

Regulation of Polychlorinated Biphenyls (PCBs) The Toxic Substances Control Act is a federal statute providing the EPA with the authority to, among other things, require use restrictions relating to chemical substances including PCBs. Generally, PCBs are prohibited from use, but some uses of PCBs - such as in electrical equipment - remain authorized under certain conditions. In April 2010, the EPA issued an advance notice of proposed rulemaking stating that it is considering revisiting the 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 IDACORP's and Idaho Power's financial condition and results of operations.

However, the financial and operational consequences cannot be determined until final regulations are issued. Idaho Power currently records asset retirement obligation liabilities and associated regulatory assets for the estimated retirement costs of equipment containing PCBs. Final regulations could accelerate Idaho Power's estimated timing for the retirement of equipment with PCBs.

Clean Water Act Matters Potential Section 316(b) Regulation of Cooling Water Intake Structures: The CWA generally prohibits the discharge of any "pollutant" from a point source into waters of the United States without a permit. Pollutants are broadly defined to include changes in temperature. Section 316(b) of the CWA requires that National Pollutant Discharge Elimination System permits for facilities with cooling water intake structures ensure that the location, design, construction, and capacity of the structures employ the best 71-------------------------------------------------------------------------------- Table of Contents technology available (BTA) to minimize harmful impacts on the environment, such as the removal of fish, fish larvae, marine mammals, and other aquatic organisms from waters of the U.S.

In March 2011, the EPA issued a proposed rule that would establish requirements under Section 316(b) of the CWA for all existing power generation facilities and existing manufacturing and industrial facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. The proposed rule establishes national requirements applicable to cooling water intake structures at these facilities that reflect the BTA for minimizing adverse environmental impacts. An existing facility may choose one of two options for meeting BTA requirements for impingement mortality under this proposed rule. The owner or operator may monitor to show the specified performance standards for impingement mortality of fish and shellfish have been met, or they may demonstrate that the intake velocity meets specified design criteria. For entrainment mortality, this proposed rule establishes requirements for studies and information as part of the permit application, and then establishes a process by which the BTA for entrainment mortality would be implemented at each facility. Since issuing the proposed rule, EPA has collected studies from the public with additional biological data, some of which may help address the intent of the proposed rule to reduce damage to ecosystems while accommodating site-specific circumstances and providing cost-effective options for compliance. Under a settlement agreement for litigation that was the impetus for the rule, the EPA was required to issue a final rule by January 2014, but the rule was not issued by the deadline. Based on the qualification criteria, Idaho Power expects that the new requirements would apply to the Jim Bridger plant, but it is unable to determine the potential increased costs that may result from implementation of the rule until the final rule is issued and cost studies are performed.

Idaho Power is also addressing CWA issues associated with the relicensing of its HCC. See "Relicensing of Hydroelectric Projects" in this MD&A for additional information on the impact of the CWA on that relicensing effort.

Effluent Limitation Guidelines and Standards: On June 7, 2013, the EPA issued proposed rulemaking to revise the technology-based effluent limitation guidelines and standards under the CWA for water discharged from steam electric power plants, which includes coal-fired plants. The proposed rule would establish new or additional requirements for wastewater streams from a number of processes associated with steam electric power generation. The EPA has stated that more than half of coal-fired plants in the United States would be in compliance with the proposed rules without incurring any additional cost, and stated that its cost analysis shows very small effects on the electric power market. Idaho Power is evaluating the proposed rule to determine its impact on Idaho Power's co-owned coal-fired plants, if the rule is adopted.

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. Management believes the accounting policies and estimates discussed below 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 had recorded $1.0 billion of regulatory assets and $387 million of regulatory liabilities at December 31, 2013. 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 could be 72-------------------------------------------------------------------------------- Table of Contents required to eliminate those regulatory assets or liabilities. Either circumstance could have a material effect on Idaho Power's financial condition or results of operations.

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 provides deferred income taxes related to its plant assets for the difference between income tax depreciation and book depreciation used for financial statement purposes. Deferred income taxes for other items are provided for the temporary differences between the income tax and financial accounting treatment of such items. Unless contrary to applicable income tax guidance, deferred income taxes are not provided for those income tax temporary differences where the prescribed regulatory accounting methods, or flow-through, direct Idaho Power to recognize the tax impacts currently for rate making and financial reporting.

Refer to Note 1 - "Summary of Significant Accounting Policies" and Note 2 - "Income Taxes" to the consolidated financial statements included in this report for additional information relating to income taxes.

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 Security Plan for Senior Management Employees (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 determined the discount rate for each plan through the construction of hypothetical portfolios of bonds selected from high-quality corporate bonds available as of December 31, 2013, with maturities matching the projected cash outflows of the plans. Based on the results of this analysis, the discount rate used to calculate the 2014 pension expense will be increased to 5.20 percent from the 4.20 percent used in 2013.

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 Idaho Power believes 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 2014 pension expense will be 7.75 percent, which is the same assumption as was used for 2013.

Gross net periodic pension and other postretirement benefit cost for these plans totaled $55 million, $51 million, and $39 million for the years ended December 31, 2013, 2012, and 2011, respectively, including amounts deferred as regulatory assets (see discussion below) and amounts allocated to capitalized labor. For 2014, gross pension and other postretirement benefit costs are expected to total approximately $35 million, which takes into account the change in the discount rate noted above. No changes were made to the other key assumptions used in the actuarial calculation.

73-------------------------------------------------------------------------------- Table of Contents 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: Discount rate Rate of return 2014 2013 2014 2013 (millions of dollars)Effect of 0.5% rate increase on net $ (6.1 ) $ (6.9 ) $ (2.8 ) $ (2.5 ) periodic benefit cost Effect of 0.5% rate decrease on net 6.5 8.0 2.9 2.4 periodic benefit cost Additionally a 0.5 percent increase in the plans' discount rates would have resulted in a $55 million decrease in the combined benefit obligations of the plans as of December 31, 2013. A 0.5 percent decrease in the plans' discount rates would have resulted in a $62 million increase in the combined benefit obligations of the plans as of December 31, 2013.

Idaho Power made contributions of $18.5 million, $44.3 million, and $30 million to the pension plan in 2011, 2012, and 2013 respectively. Idaho Power's required contributions to the pension plan during 2014 are estimated to be $1.4 million, though it plans to contribute at least $20 million to the pension plan during 2014. Under the SMSP, Idaho Power makes payments directly to participants in the plan. Benefit payments are expected to be $4.0 million in 2014, and were $3.5 million and $3.2 million for 2013 and 2012, respectively. Idaho Power did not make contributions to the postretirement benefit plan in 2013 and 2012, and does not anticipate the need for contributions to the plan in 2014.

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. In 2007, Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. At December 31, 2013, a total of $75 million of expense was deferred as a regulatory asset. Approximately $7 million is expected to be deferred in 2014. Idaho Power recorded pension expense in 2013, 2012, and 2011 of $36 million, $34 million, and $34 million, respectively.

Refer to Note 11 - "Benefit Plans" to 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, if material, 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 summary of significant accounting policies, including the discussion under "Change in Method of Accounting for Investments in Qualified Affordable Housing Projects," relating to IDACORP's adoption in 2013, with retrospective effect, of an accounting policy election to account for investments in qualified affordable housing projects using the proportional amortization method. This method change resulted in a $4.3 million increase in IDACORP's net income in 2012 and a $3.3 million increase in 2011 compared to amounts recorded under the previously applied method.

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