10-K 1 ida12311310k.htm 10-K IDA 12.31.13 10k
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
X
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 
THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
For the fiscal year ended December 31, 2013
 
OR
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
 
THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from ................... to .................................................................
 
Exact name of registrants as specified in
 
Commission
their charters, address of principal executive
IRS Employer
File Number
offices, zip code and telephone number
Identification Number
1-14465
IDACORP, Inc.
82-0505802
1-3198
Idaho Power Company
82-0130980
 
1221 W. Idaho Street
 
 
Boise, ID 83702-5627
 
 
(208) 388-2200
 
 
State of incorporation:  Idaho
 
 
Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
which registered
IDACORP, Inc.:  Common Stock, without par value
New York
 
Stock Exchange
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock
 
Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc.
Yes
(X)
No
(  )
Idaho Power Company
Yes
(  )
No
(X)
 
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
IDACORP, Inc.
Yes
(  )
No
(X)
Idaho Power Company
Yes
(  )
No
(X)
 
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  Yes  (X)  No  (  )
 
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). 
IDACORP, Inc.
Yes
(X)
No
( )
Idaho Power Company
Yes
(X)
No
( )
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  (X)
 

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Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies.
IDACORP, Inc.:
 
Large accelerated filer
(X)
Accelerated filer
(  )
Non-accelerated filer
(  )
Smaller reporting company
(  )
 
Idaho Power Company:
 
Large accelerated filer
(  )
Accelerated filer
(  )
Non-accelerated filer
(X)
Smaller reporting company
(  )
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).
IDACORP, Inc.
Yes
(  )
No
(X)
Idaho Power Company
Yes
(  )
No
(X)
 
Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2013):
IDACORP, Inc.:
 
$
2,373,645,258

 
Idaho Power Company:
 
None
Number of shares of common stock outstanding as of February 14, 2014:
IDACORP, Inc.:
50,220,039
Idaho Power Company:
39,150,812, all held by IDACORP, Inc.

Documents Incorporated by Reference:
 
Part III, Items 10 - 14
Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the 2014 annual meeting of shareholders.
 
This combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company.  Information contained herein relating to an individual registrant is filed by that registrant on its own behalf.  Idaho Power Company makes no representation as to the information relating to IDACORP, Inc.’s other operations.
 
Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.
 




2


TABLE OF CONTENTS
 
 
 
 
 
Page
 
 
 
Commonly Used Terms
Cautionary Note Regarding Forward-Looking Statements
 
 
 
Part I
 
 
 
 
 
Item 1
Business
 
Executive Officers of the Registrants
Item 1A
Risk Factors
Item 1B
Unresolved Staff Comments
Item 2
Properties
Item 3
Legal Proceedings
Item 4
Mine Safety Disclosures
 
 
 
Part II
 
 
 
 
 
Item 5
Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Item 6
Selected Financial Data
Item 7
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A
Quantitative and Qualitative Disclosures About Market Risk
Item 8
Financial Statements and Supplementary Data
Item 9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A
Controls and Procedures
Item 9B
Other Information
 
 
 
Part III
 
 
 
 
 
Item 10
Directors, Executive Officers and Corporate Governance*
Item 11
Executive Compensation*
Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*
Item 13
Certain Relationships and Related Transactions, and Director Independence*
Item 14
Principal Accountant Fees and Services*
 
 
 
Part IV
 
 
 
 
 
Item 15
Exhibits and Financial Statement Schedules
 
 
 
Signatures
 
 
 
* Except as indicated in Items 10, 12, and 14, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s definitive proxy statement for the 2014 annual meeting of shareholders.

3



COMMONLY USED TERMS
 
 
 
 
 
The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:
 
 
 
 
 
 
 
ADITC
-
Accumulated Deferred Investment Tax Credits
 
IFS
-
IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.
AFUDC
-
Allowance for Funds Used During Construction
 
IPUC
-
Idaho Public Utilities Commission
APCU
-
Annual Power Cost Update
 
IRP
-
Integrated Resource Plan
BACT
-
Best Available Control Technology
 
IRS
-
U.S. Internal Revenue Service
BCC
-
Bridger Coal Company, a joint venture of IERCo
 
kW
-
Kilowatt
BLM
-
U.S. Bureau of Land Management
 
MATS
-
Mercury and Air Toxics Standards
BPA
-
Bonneville Power Administration
 
MD&A
-
Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAA
-
Clean Air Act
 
MW
-
Megawatt
CAMP
-
Comprehensive Aquifer Management Plan
 
MWh
-
Megawatt-hour
CO2
-
Carbon Dioxide
 
NAAQS
-
National Ambient Air Quality Standards
CWA
-
Clean Water Act
 
NMFS
-
National Marine Fisheries Service
EGUs
-
Electric Utility Generating Units
 
NOx
-
Nitrogen Oxide
EIS
-
Environmental Impact Statement
 
NSPS
-
New Source Performance Standards
EPA
-
U.S. Environmental Protection Agency
 
NSR/PSD
-
New Source Review / Prevention of Significant Deterioration
EPS
-
Earnings Per Share
 
O&M
-
Operations and Maintenance
ESA
-
Endangered Species Act
 
OATT
-
Open Access Transmission Tariff
FCA
-
Fixed Cost Adjustment
 
OPUC
-
Public Utility Commission of Oregon
FERC
-
Federal Energy Regulatory Commission
 
PCA
-
Power Cost Adjustment
FPA
-
Federal Power Act
 
PCAM
-
Oregon Power Cost Adjustment Mechanism
GAAP
-
Generally Accepted Accounting Principles
 
PURPA
-
Public Utility Regulatory Policies Act of 1978
GHG
-
Greenhouse Gas
 
REC
-
Renewable Energy Certificate
HAPS
-
Hazardous Air Pollutants
 
RPS
-
Renewable Portfolio Standard
HCC
-
Hells Canyon Complex
 
SEC
-
U.S. Securities and Exchange Commission
Ida-West
-
Ida-West Energy, a subsidiary of IDACORP, Inc.
 
SMSP
-
Security Plan for Senior Management Employees
Idaho ROE
-
Idaho-jurisdiction return on year-end equity
 
SO2
-
Sulfur Dioxide
IERCo
-
Idaho Energy Resources Co., a subsidiary of Idaho Power Company
 
USFWS
-
U.S. Fish and Wildlife Service
IESCo
-
IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.
 
VIEs
-
Variable Interest Entities

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements.  In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, as well as in subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission, and the following important factors:

the effect of decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators that impact Idaho Power's ability to recover costs and earn a return;
changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the availability and use of demand-side management programs, and their associated impacts on loads and load growth;
the impacts of changes in economic conditions, including the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and collections of receivables;
unseasonable or severe weather conditions, wildfires, drought, and other natural phenomena and natural disasters, which affect customer demand, hydroelectric generation levels, repair costs, and the availability and cost of fuel for generation plants or purchased power to serve customers;
advancement of technologies that reduce loads or reduce the need for Idaho Power's generation of electric power;
adoption of, changes in, and costs of compliance with, laws, regulations, and policies relating to the environment, natural resources, and endangered species, and the ability to recover those costs through rates;
the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;
reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to credit and contractual arrangements;
variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which impact the amount of generation from Idaho Power's hydroelectric facilities;
the ability to purchase fuel and power on favorable payment terms and prices, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;
accidents, fires, explosions, and mechanical breakdowns that may occur while operating and maintaining an electric system, which can cause unplanned outages, reduce generating output, damage the companies’ assets, operations, or reputation, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties;
the ability to buy and sell power, transmission capacity, and fuel in the markets;
the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended;
administration of Federal Energy Regulatory Commission and other mandatory reliability, security, and other requirements for system infrastructure, which could result in penalties and increase costs;
disruptions or outages of Idaho Power's generation or transmission systems or of any interconnected transmission system;
the costs and operational challenges of integrating intermittent wind power or other renewable energy sources into Idaho Power's resource portfolio;

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changes in actuarial assumptions, changes in interest rates, and the return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities;
the ability to continue to pay dividends based on financial performance, and in light of contractual covenants and restrictions and regulatory limitations;
changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;
employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce and retirements, the cost and ability to retain skilled workers, and the ability to adjust the labor cost structure when necessary;
failure to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;
the inability to obtain or cost of obtaining and complying with required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;
the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and the ability to recover those costs or the costs of operational changes through insurance or rates, or from third parties;
the failure of information systems or the failure to secure information system data, failure to comply with privacy laws, security breaches, or the direct or indirect effect on the companies' business or operations resulting from cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;
unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement new technology solutions; and
adoption of or changes in accounting policies and principles, changes in accounting estimates, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.
Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

 
  


6


PART I
ITEM 1.  BUSINESS

OVERVIEW
 
IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho. Its principal operating subsidiary is Idaho Power Company (Idaho Power).  IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes record retention and reporting requirements on IDACORP.
 
Idaho Power was incorporated under the laws of the state of Idaho in 1989 as the successor to a Maine corporation that was organized in 1915 and began operations in 1916.  Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the FERC and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
  
Idaho Power's utility operations constitute nearly all of IDACORP's current business operations and are IDACORP’s only reportable business segment.  Segment financial information is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report.  As of December 31, 2013, IDACORP had 2,023 full-time employees, 2,011 of whom were employed by Idaho Power, and 19 part-time employees, 18 of whom were employed by Idaho Power.
 
IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy Services Co. (IESCo), the successor to IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.

IDACORP and Idaho Power make available free of charge on their websites their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. Securities and Exchange Commission (SEC).  IDACORP's website is www.idacorpinc.com and Idaho Power's website is www.idahopower.com.  The contents of these websites are not part of this Annual Report on Form 10-K.  Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from the SEC’s website, www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.
 
IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.

UTILITY OPERATIONS
 
Idaho Power provided electric utility service to approximately 508,000 general business customers in southern Idaho and eastern Oregon as of December 31, 2013. Over 422,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing and refining, electronics and general manufacturing, agriculture, health care, and winter recreation.  Idaho Power holds franchises, typically in the form of right-of-way arrangements, in 71 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon. Idaho Power's service area is illustrated in gray on the following page and covers approximately 24,000 square miles with an estimated population of one million.


7


Weather, seasonal customer demand, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned and associated expenses are not incurred evenly during the year.  Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak in the winter. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales.  Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps. 

Electric utilities have historically been recognized as natural monopolies and they operate in a highly regulated environment - one in which they have an obligation to provide electric service to their customers and in return receive an exclusive franchise within their service territory - with an opportunity to earn a regulated rate of return.  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). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydroelectric project relicensing, and system reliability, among other items.

Business Strategy

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business.  Idaho Power's three-part strategy can be summarized as follows:
Responsible Planning:  Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet anticipated population growth and increasing electricity demand.  This planning process integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the communities Idaho Power serves.
Responsible Development and Protection of Resources:  Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural

8


resources Idaho Power and the communities it serves depend upon.  Additionally, the strategy considers workforce planning and employee development and retention related to these strategic elements.
Responsible Energy Use:  Idaho Power's business strategy includes energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standards legislation.  The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions, as well as operating Idaho Power's system in a manner that extracts additional value through changes in fuel mix and generation.

Idaho Power regularly evaluates and refines its business strategy to ensure coordination among and integration of all functional areas of the company.  Idaho Power’s business strategy seeks to balance the interests of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. 

Rates and Revenues

The prices that the IPUC and OPUC authorize Idaho Power to charge for the electric energy and services Idaho Power sells are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.
  
Retail Rates: Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to cover its operating costs and provide an opportunity for a reasonable rate of return on its investments.  Idaho Power uses general rate cases, power cost adjustment (PCA) mechanisms, a fixed cost adjustment (FCA), balancing accounts and tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order.  Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties.  The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, are non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment as authorized by regulators. This requirement does not, however, ensure that Idaho Power will earn a specified rate of return.

In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific authorization from the IPUC or OPUC.  Deferred amounts are generally collected from or refunded to retail customers through the use of base rates or supplemental tariffs.

While authorized rates and the impact of rate mechanisms are significant drivers of the company's results, Idaho Power's results are also impacted by costs of fuel and purchased power, seasonal or atypical weather, and customer use.  Idaho Power's electric peak demand occurs in the summer. Therefore, IDACORP's and Idaho Power's revenues and associated expenses are not incurred or generated evenly throughout the year.
 
Wholesale Markets: As a public utility subject to the provisions of Part II of the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.  Idaho Power’s OATT transmission rate is revised each year based primarily on financial and operational data Idaho Power files annually with the FERC in its Form 1.  The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and network reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation.  These mandatory transmission and reliability standards were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of transmission and reliability standards.
 
Idaho Power participates in the wholesale energy markets by purchasing power to help meet load demands and selling power that is in excess of load demands.  Idaho Power's market activities are guided by a risk management policy and frequently updated operating plans. These operating plans are impacted by factors such as customer demand for power, market prices, generating costs, transmission constraints, and availability of generating resources.  Some of Idaho Power's 17 hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run hydroelectric generation units and when to store water in reservoirs.  Idaho Power at times operates its other generation facilities to take advantage of market opportunities. These decisions affect the timing and volumes of market purchases and market sales.  Even in below-normal

9


water years, there are opportunities to vary water usage to capture wholesale marketplace economic benefits, maximize generation unit efficiency and meet peak loads.  As to hydroelectric generation, compliance factors such as allowable river stage elevation changes and flood control requirements also influence these generation dispatch decisions.
 
Energy Sales: The following table presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type.  Approximately 95 percent of Idaho Power’s general business revenues originates from customers located in Idaho, with the remainder originating from customers located in Oregon.  Idaho Power’s operations, including information on energy sales, are discussed further in Part II, Item 7 - “MD&A - Results of Operations - Utility Operations.” 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
General business revenues (thousands of dollars)
 
 

 
 

 
 

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

Provision for rate refund for sharing mechanism
 
(7,602
)
 
(7,151
)
 
(27,099
)
Deferred revenue related to Hells Canyon Complex relicensing AFUDC
 
(10,776
)
 
(10,636
)
 
(10,636
)
Total general business revenues
 
1,101,728

 
937,765

 
834,545

Off-system sales
 
54,473

 
61,534

 
101,602

Other
 
86,897

 
77,426

 
86,581

Total revenues
 
$
1,243,098

 
$
1,076,725

 
$
1,022,728

Energy sales (thousands of 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 general business
 
14,619

 
14,085

 
13,734

Off-system sales
 
1,683

 
2,183

 
3,635

Total
 
16,302

 
16,268

 
17,369


Competition: Idaho Power's utility electric business has historically been recognized as a natural monopoly. Idaho Power's rates for retail electric services are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses including depreciation on capital investments, an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, compete with Idaho Power for sales to existing customers.  Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that could alter demand for Idaho Power's electric energy sales.

As noted above, Idaho Power also participates in the wholesale energy markets and in the electric transmission markets. Generally, these wholesale markets are regulated by the FERC, which requires electric utilities to transmit power to or for wholesale purchaser and sellers and make available, on a non-discriminatory basis, transmission capacity for the purpose of providing these services.

Power Supply
 
Overview: Idaho Power primarily relies on company-owned hydroelectric, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers.  Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River basin. Market purchases and sales are used to supplement Idaho Power's generation and balance supply and demand throughout the year.  Idaho Power’s generating plants and their capacities are listed in Part I, Item 2 - “Properties.”
 
Weather, load demand, and economic conditions impact power supply costs.  Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements.  Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric generating facilities and

10


reduce the need for thermal generation and wholesale market purchased power.  Economic conditions and governmental regulations can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power has PCA mechanisms in Idaho and Oregon that mitigate in large part the potentially adverse financial statement impacts of volatile fuel and power costs.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer.  The all-time system peak demand was 3,407 Megawatts (MW), set on July 2, 2013, and the all-time winter peak demand was 2,527 MW, set on December 10, 2009.  During these and other similarly heavy load periods Idaho Power’s system is fully committed to serve load and meet required operating reserves. The following table presents Idaho Power’s total power supply for the last three years.
 
 
MWh
 
Percent of Total Generation
 
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
 
 
(thousands of MWh)
 
 
 
Hydroelectric plants
 
5,656

 
7,956

 
10,937

 
42
%
 
57
%
 
69
%
Coal-fired plants
 
6,327

 
5,227

 
4,820

 
47
%
 
38
%
 
30
%
Natural gas fired plants
 
1,576

 
676

 
138

 
11
%
 
5
%
 
1
%
Total system generation
 
13,559

 
13,859

 
15,895

 
100
%
 
100
%
 
100
%
 
 
 

 
 

 
 

 
 

 
 

 
 

Purchased power - cogeneration and small power production
 
2,127

 
1,961

 
1,495

 
 

 
 

 
 

Purchased power - other
 
1,775

 
1,709

 
1,256

 
 

 
 

 
 

Total purchased power
 
3,902

 
3,670

 
2,751

 
 

 
 

 
 

Total power supply
 
17,461

 
17,529

 
18,646

 
 

 
 

 
 

 
Hydroelectric Generation: Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries.  Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generation of approximately 8.4 million Megawatt-hours (MWh) under median water conditions. The amount of hydroelectric power generated depends on several factors - the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, the amount and timing of water leases, and other weather and stream flow considerations.  Generation at the plants located on the Snake River also depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer that is connected to the Snake River.  Idaho Power participates in work groups related to water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River.  For more information on water management issues see Note 10 - "Contingencies" to the consolidated financial statements included in this report.

During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is reduced, resulting in a reliance on other generation resources and power purchases. For 2013, below average snow accumulation in the Snake River basin resulted in generation below the 8.4 million MWh historical median. Annual generation from Idaho Power’s hydroelectric facilities was 5.7 million MWh in 2013.  The Northwest River Forecast Center of the National Oceanic and Atmospheric Administration reported that Brownlee Reservoir (part of Idaho Power's Hells Canyon Complex) inflow for April through July 2013 was 2.6 million acre-feet (maf). By comparison, April through July Brownlee Reservoir inflow was 5.5 maf in 2012 and 10.5 maf in 2011. For 2014, Idaho Power estimates generation from its hydroelectric facilities of between 5.0 million MWh and 7.0 million MWh.
 
Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric projects on qualified waterways.  The licensing process includes an extensive public review process and involves numerous natural resource and environmental issues.  The licenses last from 30 to 50 years depending on the size, complexity, and cost of the project.  Idaho Power is actively pursuing the relicensing of the Hells Canyon Complex project, its largest hydroelectric generation source.  Idaho Power also has three Oregon licenses under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities. For further information on relicensing activities see Part II, Item 7 – MD&A – "Regulatory Matters – Relicensing of Hydroelectric Projects.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydroelectric operations. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectric projects are subject to conditions described in the FPA and related FERC regulations.  These conditions and regulations include provisions relating to

11


condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages, and other matters.
 
Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants:

Jim Bridger located in Wyoming, in which Idaho Power has a one-third interest;
North Valmy located in Nevada, in which Idaho Power has a 50 percent interest; and
Boardman located in Oregon, in which Idaho Power has a 10 percent interest.

Idaho Power owns a one-third interest in Bridger Coal Company (BCC), which owns the mine that supplies coal to the Jim Bridger power plant. PacifiCorp is the operator of both BCC and the Jim Bridger power plant.  The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2024 from surface and underground sources.  Idaho Power believes that BCC has sufficient reserves to provide coal deliveries for at least the term of the sales agreement.  Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2014 from the Black Butte Coal Company’s Black Butte mine located near the Jim Bridger plant.  This contract supplements the BCC deliveries and provides another coal supply to operate the Jim Bridger plant.  The Jim Bridger plant’s rail load-in facility and unit coal train, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.
 
NV Energy, Inc. is the operator of the North Valmy plant. NV Energy and Idaho Power have contracts with a coal supplier through 2015. Idaho Power's share of these contracts along with existing coal inventory at the plant are expected to meet Idaho Power's projected coal supply needs for 2014 and approximately 60 percent of its supply needs for 2015.

Portland General Electric Company is the operator of the Boardman plant. Ninety percent of the Boardman plant’s projected coal requirements is under contract for 2014. The Boardman generating plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming.  As a ten percent owner of the plant, Idaho Power is obligated to purchase ten percent of the coal obtained under these contracts. In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020.

Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined cycle power plant and the Danskin and Bennett Mountain natural gas-fired simple cycle combustion turbine power plants. All three plants are located in Idaho. The Langley Gulch power plant was placed into service in June 2012, contributing to the notable increase in gas-fired generation from 2011 to 2013.

Idaho Power operates the Langley Gulch plant as a baseload unit and the Danskin and Bennett Mountain plants to meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency.  The natural gas is transported through the Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements.  These transportation agreements vary in contract length, with the latest termination date of May 2042, but with extensions at Idaho Power’s discretion.  In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project.  This firm storage contract expires in 2043.  Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.
 
As of December 31, 2013, approximately 4.8 million MMBtu's of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through January 2015. Idaho Power plans to manage the procurement of additional natural gas for the peaking units on the daily spot market or from storage inventory as necessary to meet system requirements and fueling strategies.
 
Purchased Power: Idaho Power purchases power in the wholesale market and pursuant to long-term power purchase contracts, as described below.

Wholesale Market Transactions: To supplement its self-generated power and long-term purchase arrangements, Idaho Power purchases power in the wholesale market based on economics, operating reserve margins, risk management policy limitations, and unit availability.  Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets.


12


During 2013, Idaho Power purchased 1.8 million MWh of power through wholesale market purchases at an average cost of $47.91 per MWh. During 2012, Idaho Power purchased 1.7 million MWh of power through wholesale market purchases at an average cost of $37.94 per MWh. During 2013 and 2012, Idaho Power sold 1.7 million MWh and 2.2 million MWh, respectively, of power in wholesale market sales, with an average price of $32.37 per MWh and $28.19 per MWh, respectively.

Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has the following notable firm long-term power purchase contracts and energy exchange agreements:

Raft River Energy I, LLC - for up to 13 MW (nameplate generation) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho.  The contract term is through 2033.
Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon.  The contract term is through 2027.
USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs #1 geothermal power plant located near Vale, Oregon.  The contract term is through 2037.
Clatskanie People's Utility - for the exchange of up to 18 MW of energy from the Arrowrock hydroelectric project in southern Idaho in exchange for energy from Idaho Power's system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is through December 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms.
 
PURPA Power Purchase Contracts: Idaho Power purchases power from PURPA projects as mandated by federal law. As of December 31, 2013, Idaho Power had contracts with on-line PURPA-related projects with a total of 774 MW nameplate generation capacity, with an additional 68 MW nameplate capacity of projects projected to be on-line by the end of 2016. The power purchase contracts for these projects have terms ranging from one to 35 years. The expense and volume of PURPA project power purchases during the last three years is included in the table below.
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
PURPA contract expense (in thousands)
 
$
131,338

 
$
117,618

 
$
90,251

MWh purchased under PURPA contracts (in thousands)
 
2,127

 
1,961

 
1,495

Average cost per MWh from PURPA contracts
 
$
61.75

 
$
59.98

 
$
60.36


Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions having jurisdiction over Idaho Power have each issued orders and rules regulating Idaho Power’s purchase of power from "qualifying facilities" that meet the requirements of PURPA.  A key component of the PURPA contracts is the energy price contained within the agreements.  PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs.  The IPUC and OPUC have established specific rules and regulations to calculate the avoided cost that Idaho Power is required to include in PURPA contracts. For PURPA power purchase agreements:
 
Idaho Power is required to purchase all of the output from the facilities located inside its service territory, subject to some exceptions such as adverse impacts on system reliability.
Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive power at the facility’s requested point of delivery on Idaho Power's system.
The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the PCA, and the OPUC jurisdictional portion is recovered through general rate case filings and an Oregon PCA mechanism.
IPUC and OPUC jurisdictional regulations allow PURPA standard contract terms to be up to 20 years.
The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 kilowatts (kW) and all other types of projects that are smaller than 10 average MWs. For PURPA qualifying facilities that exceed these size limitations, Idaho Power is required to negotiate an applicable price (premised on avoided costs) based upon IPUC regulations.
The OPUC requires that Idaho Power pay the published avoided costs for all PURPA qualifying facilities with a nameplate rating of 10 MW or less and that Idaho Power negotiate an applicable price (premised on avoided costs) for all other qualifying facilities based upon OPUC regulations.

Idaho Power, as well as other power utilities with an Idaho service territory, has been engaged in proceedings at the IPUC and OPUC relating to PURPA contract terms, including the prices paid for energy purchased from PURPA projects. Refer to "MD&A - Regulatory Matters - Renewable Energy Standards and Contracts" for a summary of those proceedings.

13



Transmission Services and Federal Tariff
 
Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers.  Transmission systems are designed to move electricity over long distances because generation facilities can be located anywhere from a few miles to hundreds of miles from customers.  Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum capability and reliability.  Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy, Inc.  These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection.  Idaho Power provides wholesale transmission service for eligible transmission customers on a non-discriminatory basis.  Idaho Power is a member of the Western Electricity Coordinating Council, the Northwest Power Pool, the Northern Tier Transmission Group, and the North American Energy Standards Board.  These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the Western Interconnection.

Transmission to serve Idaho Power's retail customers is subject to the jurisdiction of the IPUC and OPUC for retail rate making purposes.  Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approved OATT.  Services under the OATT are offered on a nondiscriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system.  As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function.

Idaho Power is jointly working on the permitting of two significant transmission projects. The Boardman-to-Hemingway line is a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West line is a proposed 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 – MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.
 
Resource Planning
 
Integrated Resource Plan: The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP). Idaho Power filed its most recent IRP with the IPUC and OPUC in June 2013.  The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side and demand-side resource options, and identifies potential near-term and long-term actions.  The four primary goals of the IRP are to: 

identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's service area throughout the 20-year planning period;
ensure the selected resource portfolio balances cost, risk, and environmental concerns;
give equal and balanced treatment to both supply-side resources and demand-side measures; and
involve the public in the planning process in a meaningful way.
 
During the time between IRP filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect changes in technology, economic conditions, anticipated resource development, and regulatory requirements.

The 2013 IRP included a projected median annual average load growth rate of 1.1 percent over the next 20 years and a median annual average peak-hour load growth rate of 1.4 percent over the 20-year period. By contrast, the 2011 IRP included a forecast median annual average load growth rate of 1.4 percent and an annual average peak-hour load growth rate of 1.8 percent. The 2013 IRP's long-term growth assumptions include several changes relative to the growth forecasts included in the 2011 IRP, including (a) changes in expectations surrounding economic conditions, (b) anticipated electricity price increases incorporating impacts of carbon legislation, (c) loss of anticipated load from the Hoku Materials, Inc. special customer contract, and (d) per the directive of the OPUC, and notwithstanding the level of historic and recent service inquiries from potential new large-load customers and Idaho Power's economic development initiatives, the elimination of load from an anticipated but unidentified large-load customer that had been included in the 2011 IRP. Subsequent to the filing of the 2013 IRP, Idaho Power conducted an updated load forecast based on observations of more current economic activity. The updated 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. There is a considerable degree of uncertainty in the growth forecast used for long-term resource

14


planning purposes, and Idaho Power's actual supply-side resource needs could change significantly from those outlined in the 2013 IRP.

The 2013 IRP also includes a projected preferred resource portfolio, which identifies the Boardman-to-Hemingway transmission line as the major near-term supply-side resource addition, as well as a number of significant plant upgrades and environmental control technology installations. Idaho Power believes the Boardman-to-Hemingway transmission line and the existing Hemingway substation, together with the Gateway West transmission line, will improve reliability, relieve transmission congestion, and provide system flexibility. Notwithstanding the preferred portfolio identified in the 2013 IRP, 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.

Studies that Idaho Power conducted in connection with the 2013 IRP indicate that under a scenario that excludes approximately 400 MW of demand response programs and power capacity from the proposed Boardman-to-Hemingway transmission line, no peak-hour load deficit exists until 2016. This result suggests there may be available near term capacity to accommodate growth from economic development or increases in customers and loads. Idaho Power expects to be able to manage near-term summer peak capacity deficits until completion of the Boardman-to-Hemingway transmission line, which is expected to be in service in 2020 or beyond. If the Boardman-to-Hemingway line is not constructed by the time necessary to meet load demand, Idaho Power will need to identify alternatives to meet load requirements. Should estimates of higher growth rates materialize, or were there to be a significant increase in loads due to new, unanticipated large-load customers, Idaho Power could be required to adjust its infrastructure development timing and plans accordingly.

By January 1, 2020, Idaho Power is required to own or contract to purchase the capacity and output from a qualifying solar photovoltaic (PV) system with a minimum capacity of 500 kW pursuant to the state of Oregon's solar PV capacity standard. The timing of development of this required project in Oregon will depend in large part on Idaho Power's ability to resolve integration, reliability, and cost issues associated with the influx of PURPA resources from which Idaho Power is currently mandated to purchase power. However, in light of advances in solar PV technology, Idaho Power believes it will likely become more prevalent in its service area over the long term.

Integration of Intermittent Resources: In response to the operational challenges associated with integrating intermittent wind power that Idaho Power must purchase pursuant to PURPA, and the recognition that the costs and challenges associated with integrating intermittent resources will become even more pronounced as the volume of intermittent resources in Idaho Power's portfolio increases, Idaho Power continues efforts to better understand the effects of wind generation on power system operation.  As part of these efforts, Idaho Power issued its first wind integration study in 2007, and in late 2012 completed a second, more comprehensive wind integration study.  The goal of the most recent study was to assess the additional costs incurred in modifying operations of Idaho Power's dispatchable generating resources to compensate for the variable and intermittent energy supplied by wind generators while maintaining reliable energy delivery to customers.  Additionally, the study aimed to provide insight on the maximum amount of wind generation Idaho Power's system can accommodate without impacting reliability.  Idaho Power released the report publicly in February 2013 as part of its 2011 IRP update. In further response to the integration challenges, Idaho Power has implemented an internally developed wind forecasting system, in recognition that cost-intensive modifications to operations intended to integrate wind are reduced, though not eliminated, with improved wind production forecasting.

In the second half of 2013, Idaho Power also launched a solar integration study, which like the wind integration study is designed to determine the additional cost incurred due to the variable and intermittent nature of solar generation. Idaho Power expects to complete the solar integration study by mid-2014.

Energy Efficiency and Demand Response Programs: Idaho Power has 18 energy efficiency and demand response programs targeting energy savings across the entire year and summer system demand reduction.  These programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand.  This energy and demand reduction can minimize or delay the need for new infrastructure.  Idaho Power’s programs include:
 

15


financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
energy efficiency for new and existing homes, including efficient appliances and HVAC equipment, energy efficient building techniques, insulation improvement, air duct sealing, and energy efficient lighting;
incentives to industrial and commercial customers for acquiring energy efficient equipment, and using energy efficiency techniques for operational and management processes; and
demand response programs to reduce peak summer demand through the voluntary interruption of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through a third-party demand response aggregator.
 
In 2013, Idaho Power’s energy efficiency programs reduced energy usage by approximately 122,000 MWh. Idaho Power filed an application with the IPUC in December 2012 and with the OPUC in February 2013 to temporarily suspend two of its three demand response programs (the A/C Cool Credit and Irrigation Peak Rewards programs) for the summer of 2013. These filings were a result of an analysis conducted for Idaho Power’s 2013 IRP, which suggested a lack of peak-hour resource deficits until 2016 under some assumptions. The temporary program suspensions allowed Idaho Power to work with the IPUC, the OPUC, and interested parties to address the near-term need for the demand response programs. In April 2013, the IPUC issued an order approving a settlement stipulation providing for the temporary suspension of both demand response programs during 2013 and scheduling workshops to evaluate those programs for use in 2014 and thereafter. Following several public workshops, in October 2013 Idaho Power filed with the IPUC a settlement agreement executed by Idaho Power, the IPUC Staff, and several interested parties that provided for the reinstatement of the two suspended demand response programs in 2014 and beyond, and continuation of the third program. The settlement agreement included several program changes that Idaho Power expects will decrease program costs through lower incentive payments and will increase Idaho Power's operational flexibility. The IPUC approved the settlement agreement in November 2013. The OPUC also approved the temporary program suspension in April 2013 and approved a similar settlement agreement in December 2013.

In 2013, Idaho Power expended approximately $27 million on energy efficiency and demand response programs. Funding for those programs is provided by Idaho and Oregon energy efficiency tariff riders, base rates, and the Idaho PCA mechanism.

Environmental Regulation and Costs
 
Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment.  Environmental regulation continues to impact Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with environmental regulations, and the modification of system operations to accommodate environmental regulations.  In addition to generally applicable regulations, the FERC licenses issued for Idaho Power’s hydroelectric generating plants have numerous environmental requirements, such as the aeration of turbine water to meet dissolved gas and temperature standards in the waters downstream from the plants.  Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies.  Idaho Power's three coal-fired power plants and three natural gas combustion turbine power plants are also subject to a broad range of environmental requirements, including air quality regulation.  For a more detailed discussion of these and other environmental issues, refer to Item 7 – MD&A – "Environmental Matters" in this report.

Cost Estimates: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, especially with additional regulation under discussion at the federal level.  Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding allowance for funds used during construction (AFUDC) (in millions of dollars):
Environmental Expenditures
 
2014
 
2015 - 2016
Capital expenditures:
 
 
 
 
Studies and measures at hydroelectric facilities
 
$
12

 
$
27

Investments in equipment and facilities at thermal plants
 
64

 
78

Total capital expenditures
 
$
76

 
$
105

Operating expenses:
 
 
 
 
Operating costs for environmental facilities - hydroelectric
 
$
20

 
$
40

Operating costs for environmental facilities - thermal
 
10

 
25

Total operations and maintenance
 
$
30

 
$
65


16


 
Idaho Power anticipates that a number of new and impending U.S. Environmental Protection Agency rulemakings and other proceedings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs in addition to the amounts set forth above, but Idaho Power is unable to estimate those costs given the uncertainty associated with potential future regulations.

Environmental Controls Cost Study: In connection with its IRP process, in February 2013 Idaho Power filed with the IPUC and OPUC the results of cost studies and scenario analyses conducted to assess the potential future investments necessary for the continued operation of the Jim Bridger and North Valmy coal-fired generation facilities. The Boardman plant was not included in the study because of the existing schedule to cease coal-fired operations at that plant by the end of 2020. The analysis compared the cost of future compliance with regulations to the cost of replacement generation capacity provided by combined-cycle combustion turbine technology and conversion of the units to natural gas. Because of the speculative nature of many of the future requirements, the analysis was performed under a range of fuel pricing assumptions, carbon cost assumptions, plant upgrade and retirement costs, environmental regulation assumptions, and replacement costs. Idaho Power concluded in its study that the Jim Bridger and North Valmy plants should be retained in its resource portfolio as coal-fired plants, and supports planned investments in environmental controls at those plants. This is particularly true in light of the desire to maintain a diversified portfolio of generation assets and fuel diversity that can mitigate risk associated with increases in natural gas prices. However, Idaho Power will continue to monitor environmental requirements to assess whether environmental control upgrades remain economically appropriate.
  
Voluntary CO2 Intensity Reduction Goal: While there is currently no national mandatory greenhouse gas reduction requirement, Idaho Power continues to prepare for potential legislative and/or regulatory restrictions on emissions in order to help reduce the costs of complying with such restrictions on its customers. To that end, Idaho Power is engaged in voluntary greenhouse gas emissions intensity reduction efforts.  In September 2009, IDACORP's and Idaho Power's boards of directors approved guidelines that established a goal to reduce Idaho Power's resource portfolio's average carbon dioxide (CO2) emissions intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO2 emissions intensity of 1,194 lbs CO2/MWh.  Idaho Power's estimated CO2 emissions intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was 871 lbs/MWh, 677 lbs/MWh, and 1,060 lbs/MWh for 2012, 2011, and 2010, respectively. The combination of effective utilization of hydroelectric projects, above average stream flows in some years, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant positioned Idaho Power to extend its CO2 emissions intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period.

Sustainability Report: In May 2012, IDACORP publicly issued its inaugural sustainability report, and in May 2013 IDACORP issued its second sustainability report. The sustainability report highlights Idaho Power's continuing efforts to operate in a manner that supports financial, environmental, and social stewardship.

IFS
 
IFS invests in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk.  Over 90 percent of IFS’s investments have been made through syndicated funds. These investments cover 49 states, Puerto Rico, and the U.S. Virgin Islands.  The underlying investments include approximately 370 individual properties, of which all but four are administered through syndicated funds. IFS’s investment portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. At December 31, 2013, the gross amount of IFS’s portfolio equaled $192 million in tax credit investments.  IFS generated tax credits of $5.5 million, $5.5 million, and $6.4 million in 2013, 2012, and 2011, respectively. 

IDA-WEST
 
Ida-West operates and has a 50 percent ownership interest in nine hydroelectric projects that have a total generating capacity of 45 MW.  Four of the projects are located in Idaho and five are in northern California.  All nine projects are “qualifying facilities” under PURPA.  Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $9 million each year from 2011 to 2013.


17


EXECUTIVE OFFICERS OF THE REGISTRANTS
 
The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below, along with their business experience during at least the past five years.  Mr. J. LaMont Keen and Mr. Steven R. Keen are brothers.  There are no other family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was appointed.
 
Senior Executive Officers (in alphabetical order)

DARREL T. ANDERSON, 55
President and Chief Executive Officer of Idaho Power Company, January 1, 2014 - present.
President and Chief Financial Officer of Idaho Power Company, January 1, 2012 - December 31, 2013.
Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 1, 2009 - present.
Executive Vice President, Administrative Services and Chief Financial Officer of Idaho Power Company, October 1, 2009 - December 31, 2011.
Senior Vice President - Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, July 1, 2004 - September 30, 2009.
Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company.
 
REX BLACKBURN, 58
Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power Company, April 1, 2009 - present.
Senior Attorney, Idaho Power Company, January 1, 2008 - March 31, 2009.
 
LISA A. GROW, 48
Senior Vice President - Power Supply of Idaho Power Company, October 1, 2009 - present.
Vice President - Delivery Engineering and Operations of Idaho Power Company, July 20, 2005 - September 30, 2009.
 
J. LAMONT KEEN, 61
President and Chief Executive Officer of IDACORP, Inc., July 1, 2006 - present.
Chief Executive Officer of Idaho Power Company, November 17, 2005 - December 31, 2013.
President of Idaho Power Company, March 1, 2002 - December 31, 2011.
Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company.

STEVEN R. KEEN, 53
Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 1, 2014 - present.
Vice President - Finance and Treasurer of IDACORP, Inc., June 1, 2010 - present.
Senior Vice President - Finance and Treasurer of Idaho Power Company, January 1, 2012 - December 31, 2013.
Vice President - Finance and Treasurer of Idaho Power Company, June 1, 2010 - December 31, 2011.
Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 - May 31, 2010.
 
DANIEL B. MINOR, 56
Executive Vice President and Chief Operating Officer of Idaho Power Company, January 1, 2012 - present.
Executive Vice President of IDACORP, Inc., May 20, 2010 - present.
Executive Vice President - Operations of Idaho Power Company, October 1, 2009 - December 31, 2011.
Senior Vice President - Delivery of Idaho Power Company, July 1, 2004 - September 30, 2009.
 
Other Executive Officers (in alphabetical order)

PATRICK A. HARRINGTON, 53
Corporate Secretary of IDACORP, Inc. and Idaho Power Company, March 15, 2007 - present.
 
WARREN KLINE, 58
Vice President - Customer Operations of Idaho Power Company, May 20, 2010 - present.
Vice President - Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 - May 19, 2010.
 
LONNIE KRAWL, 50
Vice President and Chief Information Officer of Idaho Power Company, October 1, 2013 - present.

18


Director of Human Resources of Idaho Power Company, July 25, 2009 - September 30, 2013.
Director of Development and Performance Improvement of Idaho Power Company, May 30, 2006 - July 24, 2009.

LUCI K. MCDONALD, 56
Vice President - Human Resources and Corporate Services of Idaho Power Company, May 20, 2010 - present.
Vice President - Human Resources and Corporate Services of IDACORP, Inc., May 20, 2010 - December 31, 2011.
Vice President - Human Resources of IDACORP, Inc. and Idaho Power Company, December 6, 2004 - May 19, 2010.
 
KEN W. PETERSEN, 50
Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2014 - present.
Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - December 31, 2013.
Corporate Controller of IDACORP, Inc. and Idaho Power Company, December 29, 2007 - May 19, 2010.
 
N. VERN PORTER, 54
Vice President - Delivery Engineering and Construction of Idaho Power Company, May 17, 2012 - present.
Vice President - Delivery Engineering and Operations of Idaho Power Company, October 1, 2009 - May 16, 2012.
General Manager of Power Production of Idaho Power Company, April 22, 2006 - September 30, 2009.

GREGORY W. SAID, 59
Vice President - Regulatory Affairs of Idaho Power Company, January 20, 2011 - present.
General Manager of Regulatory Affairs of Idaho Power Company, April 3, 2010 - January 19, 2011.
Director, State Regulation of Idaho Power Company, August 23, 2008 - April 2, 2010.

LORI D. SMITH, 53
Vice President and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
Vice President - Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2008 - May 19, 2010.

ITEM 1A.  RISK FACTORS
 
IDACORP and Idaho Power operate in a business environment that involves significant risks, many of which are beyond the companies' control. The circumstances and factors set forth below may have a material impact on the business, financial condition, or results of operations of IDACORP and Idaho Power and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements. These risk factors, as well as other information in this report and in other reports the companies file with the SEC, should be considered carefully when evaluating IDACORP and Idaho Power.
 
If the Idaho Public Utilities Commission, the Public Utility Commission of Oregon, or the Federal Energy Regulatory Commission grant less rate recovery in regulatory proceedings than Idaho Power needs to cover existing and future costs and earn an acceptable rate of return, IDACORP's and Idaho Power's financial condition and results of operations may be adversely affected.  The prices that the Idaho Public Utilities Commission and Public Utility Commission of Oregon authorize Idaho Power to charge for its retail services, and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power to charge for its transmission services, are generally the most significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, and financial condition.  The Idaho Public Utilities Commission and the Public Utility Commission of Oregon have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred. Rates are generally established based on a test year, and the rates ultimately approved by regulators may not match expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates.

Further, while rate regulation is premised on the assumption that rates will be established that are fair, just, and reasonable, regulators have considerable discretion in applying this standard.  Thus, the regulatory process does not assure that Idaho Power will be able to fully recover its costs or achieve the rate of return allowed by the Idaho and Oregon public utility commissions and the Federal Energy Regulatory Commission.  In a number of proceedings in recent years, Idaho Power has been denied recovery, or deferred recovery pending the next general rate case, including denials or deferrals related to compensation expenses and construction expenditures. In some instances, denial of recovery may cause IDACORP and Idaho Power to record an impairment of assets. If Idaho Power's costs are not fully and timely recovered through the rates ultimately approved

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by regulators, IDACORP's and Idaho Power's financial condition and results of operations, and its ability to earn a return on investment and meet financial obligations, could be adversely affected.

For additional information relating to Idaho Power's regulatory framework and recent regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, and Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters" in this report.
 
Idaho Power's cost recovery deferral mechanisms and methods may not function as intended, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustment in Idaho that provide for periodic adjustments to the rates charged to its retail customers.  The power cost adjustment mechanisms track Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs being recovered in retail rates.  A majority, but not all, of the variance between these two amounts is deferred for future recovery from, or refund to, customers through rates.  Consequently, the power cost adjustment mechanisms only partially offset the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydroelectric generation, and volatile wholesale energy prices.  When costs rise above the level recovered in current retail rates it adversely affects Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers.

Unanticipated changes in loads in Idaho Power’s service territory expose Idaho Power to market and operational risk and could increase costs and adversely affect IDACORP's and Idaho Power's results of operations and financial condition.  To plan for future resource needs, Idaho Power prepares and periodically updates a load forecast as part of its integrated resource planning process. In doing so, Idaho Power makes load estimates that are based on a number of factors that are uncertain and difficult to estimate, and any unanticipated increase in the demand for energy could result in increased reliance on higher-cost purchased power to meet peak system demand, the need to initiate new demand response and energy efficiency programs, or the need for investment in additional generation resources.  If the incremental costs associated with the unanticipated changes in loads exceed the incremental revenue received from those sales, and Idaho Power is unable to secure timely and full rate relief to recover those costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition and results of operations. 

National and regional economic conditions may reduce customer growth rates, reduce energy consumption, or cause increased late payments and uncollectible customer accounts, which would adversely affect IDACORP's and Idaho Power's financial condition and results of operations As noted above, unanticipated increases in loads can cause operational and resource issues. Similarly, decreases in loads have the potential to adversely affect IDACORP and Idaho Power. The regional economy in which Idaho Power operates is influenced by conditions in the agriculture, recreation, technology, medical, and other industries, and as these conditions change, IDACORP's and Idaho Power's revenues will be impacted.  The direction and relative strength of the economy has been uncertain in recent years, as evidenced by, for instance, weak real estate markets, difficulties in the financial services sector and credit markets, and high unemployment. Weak economic conditions may reduce the amount of energy Idaho Power’s customers consume, result in a loss of customers (including large-load industrial and commercial customers) or further decrease the customer growth rate, and increase the likelihood and prevalence of late payments and uncollectible accounts.  A resulting decrease in overall customer usage or collections and load growth may alter capital spending plans and rate base growth and may reduce revenues, earnings, and cash flows, which could adversely affect IDACORP's and Idaho Power's financial condition and results of operations.

Extreme weather events and their associated impacts, such as high winds and fires, can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. Extreme weather events and their associated impacts can damage generation facilities and disrupt transmission and distribution systems, causing service interruptions and extended outages, increasing supply chain costs, and limiting Idaho Power's ability to meet customer energy demand.  The effect of the failure of Idaho Power's facilities to operate as planned under extreme weather conditions would be particularly burdensome during peak demand periods. Disruption in generation, transmission, and distribution systems due to weather-related factors also increases operations and maintenance expenses and could negatively affect IDACORP's and Idaho Power's results of operations and financial condition.

New advances in power generation, energy efficiency, or other technologies that impact the power utility industry could cause an erosion in revenues. Idaho Power primarily generates power at large central facilities, which results in economies of scale and lower costs than many newer generation technologies. However, with the increasing costs of energy has come the incentive for the development of new technologies for power generation and energy efficiency, and an investment in research and development to make those technologies more efficient and cost-effective. For instance, while solar technology remains a

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relatively high-cost means of power generation, there have been numerous recent advancements in the design of solar generation facilities and the materials used in panels that may further increase the efficiency and power output of solar generation sources. There is potential that power generation systems provided by third parties, whether solar generation or otherwise, could become sufficiently cost-effective and efficient that an increasing number of customers choose to install such systems on their homes or businesses. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting. Energy efficiency programs, including programs sponsored by Idaho Power, are designed to reduce energy demand. If Idaho Power is unable to maintain regulatory solutions allowing for recovery, declining usage would result in under-recovery of fixed costs. Widespread adoption of distributed generation and declining usage may decrease the need for energy supplied by Idaho Power, which would reduce Idaho Power's revenue, potentially result in the impairment of assets that produce and deliver energy, and have a negative impact on IDACORP's and Idaho Power's results of operations and financial condition.

Capital expenditures for power generation, transmission, and delivery infrastructure and replacement of that infrastructure, risks associated with construction of that infrastructure, and the timing and availability of cost recovery for the expenditures, can significantly affect IDACORP's and Idaho Power's financial condition and results of operations.  Idaho Power’s business is capital intensive and requires significant investments in energy generation, transmission, and distribution infrastructure.  A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, long-term anticipated increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure. For instance, Idaho Power is in the permitting process for two 500-kV transmission line projects.  Construction projects are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:

the ability to timely obtain labor or materials at reasonable costs, and defaults by contractors;
equipment, engineering, and design failures;
adverse weather conditions;
availability of financing;
the ability to obtain and comply with permits and land use rights, and environmental constraints;
disputes and litigation with third parties; and
changes in applicable laws or regulations.

If Idaho Power is unable to complete the construction of a project, or incurs costs that regulators do not deem prudent, it may be unable to recover its costs in full through rates or on a timely basis. In many instances, review by regulators of the prudence of investments will not occur until expenditures have been made. Even if Idaho Power completes a construction project, the total costs may be higher than estimated and/or higher than amounts approved for recovery by regulators. If Idaho Power does not receive timely recovery through rates of costs associated with those expansion and reinforcement activities, Idaho Power will have to rely more heavily on external debt or equity financing for its capital expenditures.  These large capital expenditures may weaken the financial profile of IDACORP and Idaho Power.  

Further, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, such as the Boardman-to-Hemingway transmission line, it may terminate those projects and, as an alternative, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. 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 if regulators deny recovery of costs they deem imprudently incurred, which could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power’s business is subject to an extensive set of environmental laws, rules, and regulations, which could impact Idaho Power's operations and increase costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. A number of federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, natural resources, and health and safety are applicable to Idaho Power's operations.  Many of these laws and their associated impacts are described in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. These laws and regulations generally require Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other approvals, and may be enforced by both public officials and private individuals.  Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties. 

Environmental regulations have created the need for Idaho Power to install new pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its owned or co-owned facilities, often at a substantial cost. For instance, Idaho Power plans to install environmental control apparatus at its co-owned Jim Bridger power plant in 2015 and

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2016 at a cost of approximately $130 million, and a second set of control apparatus in 2021 and 2022. Idaho Power expects that there will be other costs relating to environmental regulations, and those costs are likely to be substantial. Idaho Power is not guaranteed recovery of those costs, and regulators may not grant prior approval of cost recovery. For example, in 2013 Idaho Power filed an application with the Idaho Public Utilities Commission requesting a binding commitment to provide rate base treatment for Idaho Power's $130 million share of the capital investment in environmental control upgrades at a co-owned coal-fired generating plant. In December 2013, the commission declined to grant binding rate recovery through rates, reserving the prudence determination for subsequent proceedings. Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its existing infrastructure or construction of new infrastructure.  If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's generation or transmission facilities could be delayed, halted, or subjected to additional costs. At the same time, consumer preference for renewable or low greenhouse gas-emitting sources of energy could impact the desirability of generation from existing sources and require significant investment in new generation and transmission resources. If Idaho Power is unable to recover in full these increased costs through the ratemaking process, such non-recovery would negatively impact IDACORP's and Idaho Power's financial condition and results of operations.

Additionally, there are legislative and rulemaking initiatives pending at the federal level and the state level that are aimed at the reduction of fossil fuel plant emissions. Future changes in environmental laws or regulations governing emissions reduction may result in increased compliance costs or additional operating restrictions, require Idaho Power to purchase emission rights and pay new taxes, impair the value of Idaho Power's generating plants, or make some of those plants uneconomical to maintain or operate.

Relicensing of the Hells Canyon hydroelectric project and construction of the proposed Gateway West and Boardman-to-Hemingway 500-kV transmission lines requires consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas.  The presence of sage grouse in the vicinity of the Gateway West and Boardman-to-Hemingway transmission projects has required more extensive, costly, and time consuming evaluation and engineering.  These and other requirements of the Endangered Species Act, Clean Air Act, Clean Water Act, and similar environmental laws may increase costs, adversely affect the timing or ability to complete major projects, and may have an adverse effect on IDACORP's and Idaho Power's results of operations and financial condition.

Factors contributing to lower hydroelectric generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations.  Idaho Power derives a significant portion of its power supply from its hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, snowpack, the timing of run-off, drought conditions, and the availability of water in the Snake River basin can significantly affect its operations.  The combination of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho.  Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the over-appropriation dispute.  Diversions from the Snake River for aquifer recharge or the loss of water rights may further reduce Snake River flows available for hydroelectric generation.  When hydroelectric generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and purchased power; therefore, costs increase and opportunities for off-system sales are reduced, reducing earnings.  Through its power cost adjustment mechanisms, Idaho Power expects to recover most of the increase in net power supply costs caused by lower hydroelectric generation. Recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, negatively affecting cash flows and liquidity.

Conditions imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition.  For the last several years, Idaho Power has been engaged in an effort to renew its federal license for its largest hydroelectric generation source, the Hells Canyon Complex.  Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions.  The listing of various species of marine life, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects.  In particular, fish and other marine life recovery plans may require major operational changes to the region’s hydroelectric projects.  In addition, new interpretations of existing laws and regulations could be adopted or become applicable to hydroelectric facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power’s energy requirements.
 

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In 2007, the Federal Energy Regulatory Commission Staff issued a final environmental impact statement for the Hells Canyon Complex, which the Federal Energy Regulatory Commission will use in part to determine whether, and under what conditions, to issue a new license for the Hells Canyon Complex.  Certain portions of the final environmental impact statement involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act and formal consultations under the Endangered Species Act, which remain unresolved.  One significant issue involves water temperature gradients, and certain parties in the relicensing proceedings have advocated for the installation of water temperature management apparatus which, if required to be installed, would require substantial capital expenditures to construct and maintain.  Idaho Power may be unable to recover in full the costs of such an apparatus through rates, particularly given the magnitude of any potential impact on customer rates.  Idaho Power also cannot predict the requirements that might be imposed during the relicensing process, the financial impact of those requirements, or whether a new multi-year license will ultimately be issued.  Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs (including power purchase costs), and reduce hydroelectric generation, which could negatively affect results of operations and financial condition.

IDACORP's and Idaho Power's operating results are subject to seasonal fluctuations, and unusually mild or extreme temperatures and weather can impact their results of operations and financial condition. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. The loads required by irrigation customers in Idaho Power's service area can also create significant seasonal changes in usage. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, unusually mild weather or the timing and extent of precipitation in the future could adversely impact IDACORP's and Idaho Power's results of operations and financial condition.

Complying with state or federal renewable portfolio standards could increase capital expenditures and operating costs and adversely affect IDACORP's and Idaho Power's results of operations and financial condition.  A number of states have adopted renewable portfolio standards, which require that electricity providers obtain a minimum percentage of their power from renewable energy sources by a specified date.  Idaho Power’s operations in Oregon will be required to comply with a ten percent renewable portfolio standard beginning in 2025, and it is possible that other states, including Idaho, could adopt renewable portfolio standards.  The cost of purchasing or generating power from renewable energy sources is often greater than fossil fuel and hydroelectric generation sources, and construction of renewable energy facilities involves significant capital expenditures. As a result, new state or federal renewable portfolio standards could increase capital expenditures and operating costs and negatively affect results of operations and financial condition.

Idaho Power’s reliance on coal and natural gas to fuel its non-hydroelectric power generation facilities exposes it to the risk of increased costs and reduced earnings.  As part of its normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term contracts, often with variable-pricing terms. Market prices for coal and natural gas are influenced by factors impacting supply and demand such as weather conditions, fuel transportation availability, economic conditions, and changes in technology. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming. Any disruption of coal production in, or transportation from, that region may cause Idaho Power to incur additional fuel supply costs or use alternative generation sources or wholesale market power purchases. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. Natural gas transportation to Idaho Power's natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply disruptions. Idaho Power is also exposed to the risk that its counterparties to fuel purchase arrangements will default on their obligations, causing Idaho Power to seek alternative sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power may not be able to fully recover these increased costs through rates or its power cost adjustment mechanisms, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.
 
Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry.  Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes, accidents and workforce safety matters, release of hazardous or toxic substances into the air, water, or ground, acts of terrorism or sabotage, the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities.  Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, and regulatory inquiries and fines.  Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses for alternative fuels or wholesale

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market power purchases. Accidents, fires, explosions, system damage or dysfunction, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and may expose Idaho Power to claims for personal injury or property damage. Further, the transmission system in Idaho Power's service territory is constrained, limiting the ability to transmit electric energy within the service territory and access electric energy from outside the service territory during high-load periods. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, or not being able to access lower cost sources of electric energy, which could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

Volatility in the financial markets, or denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing, or result in losses on investments.  IDACORP and Idaho Power use short-term and long-term debt as a significant source of liquidity and funding for capital requirements not satisfied by operating cash flow. Financial markets have in recent years experienced extreme volatility and disruption, at times resulting in a decrease in the availability of liquidity and credit for borrowers.  In a volatile credit environment, Idaho Power may be unable to issue short-term or long-term debt at reasonable interest rates or at all, one or more of the participating banks in IDACORP’s and Idaho Power’s credit facilities may default on their obligations to make loans under, or may withdraw from, the credit facilities, or IDACORP’s and Idaho Power’s access to capital may otherwise be inhibited.  In addition, at times Idaho Power has a relatively large balance of short-term investments.  Volatility in the financial markets may result in a lack of liquidity for short-term investments and declines in value of some investments.  The occurrence of any of these events could affect Idaho Power's ability to execute its business plan and adversely affect IDACORP’s and Idaho Power’s results of operations and financial condition. Further, Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations. Notably, without additional approval from those commissions, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million. Idaho Power maintains its credit facilities primarily to provide back-up for commercial paper programs. These facilities include financial covenants that limit the amount of debt that can be outstanding as a percentage of total capital. Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. Failure to maintain these covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could adversely impact IDACORP's and Idaho Power's financial condition and liquidity.
 
A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties.  Access to capital markets is important to IDACORP's and Idaho Power's ability to operate and to complete capital projects, including its planned transmission projects. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and mechanisms, management and their effectiveness, resource risks and power supply costs, and other factors. These ratings impact access to, and the cost of, borrowing.  IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing.  Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access capital, including commercial paper markets, require the companies to pay a higher interest rate on their debt, and require the companies to post additional performance assurance collateral with transaction counterparties.

Idaho Power’s risk management policy and programs relating to economically hedging power and gas exposures, financial and interest rate risk, and counterparty creditworthiness may not always perform as intended, and as a result IDACORP and Idaho Power may suffer economic losses.  Idaho Power enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financial hedges to mitigate in part price exposure. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative instruments, and any such failure to mitigate exposure could result in financial losses. Further, forecasts of future fuel needs and loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position.  To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions. As a result, risk management actions may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations.


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Idaho Power could be subject to penalties and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability standards issued by the North American Electric Reliability Corporation and enforced by the Federal Energy Regulatory Commission. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Further, Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council, as applicable.  Potential monetary and non-monetary penalties for a violation of Federal Energy Regulatory Commission regulations may be substantial, and in some circumstances monetary penalties may be as high as $1 million per day per violation.  The imposition of penalties on Idaho Power could have a negative effect on its and IDACORP’s results of operations and financial condition.

Federally mandated purchases of power from PURPA power projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. An abundance of intermittent, non-dispatchable wind power generation at times when Idaho Power has available lower-cost resources to meet load demands has an impact on the operation of Idaho Power's hydroelectric generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Wind power generated from PURPA projects, which Idaho Power is generally obligated to purchase regardless of the then-current load demand or wholesale energy market prices, increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, increasing power purchase costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will increase as a result of its efforts to integrate intermittent, non-dispatchable power from a large number of PURPA power projects. Recent efforts to obtain further authorization to curtail certain intermittent power sources during light-load times have been unsuccessful. Idaho Power anticipates that costs will escalate as the volume of wind and other intermittent power on Idaho Power's system increases, which may negatively affect IDACORP's and Idaho Power's results of operations and financial condition.

The performance of pension and postretirement benefit plan investments and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily cash flows and liquidity.  Idaho Power provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees.  Costs of providing these benefits are based in part on the value of the plans' assets and, therefore, adverse investment performance for these assets could increase Idaho Power’s plan costs and funding requirements related to the plans.  The key actuarial assumptions that affect funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations.  Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations.  Estimates of future equity and debt market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use to develop the actuarial assumptions are inherently uncertain, and actual results could vary significantly from the estimates.  Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements.  Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through rates, cash contributions to the plans could reduce the cash available for the companies' businesses and dividends. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 11 - "Benefit Plans" to the consolidated financial statements included in this report.

As a holding company, IDACORP does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments.  IDACORP is a holding company with no significant operations of its own, and its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power.  IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other payments.  The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiary's actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which may reduce or cease payment of dividends at any time. See Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities" in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.

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Employee workforce factors, including the impacts of an aging workforce with specialized utility-specific functions, could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations.  Idaho Power is subject to workforce factors, including loss or retirement of key personnel, availability of qualified personnel, an aging workforce, and impacts of efforts to organize the workforce. A unionization attempt that was launched in late-2012 was unsuccessful, but does not prevent future unionization attempts. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, and generation plant operators, require extensive, specialized training.  Idaho Power expects that a significant portion of its skilled workforce will be retiring within the current decade, which will require Idaho Power to attract, train, and retain skilled workers to prevent a loss of institutional knowledge and avoid a skills gap.  Without a skilled workforce, Idaho Power’s ability to provide quality service to its customers and meet regulatory requirements will be challenging, which could negatively affect earnings.  The costs associated with attracting and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.
 
IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims.  From time to time in the normal course of business IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other relief. These matters are subject to a number of uncertainties, and as a result management is often unable to predict the outcome of a matter. As an example, over the past decade Idaho Power has been a party to proceedings relating to high prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001, which caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the Federal Energy Regulatory Commission to initiate its own investigations. While Idaho Power has largely disposed of direct claims in those proceedings, the settlements and associated Federal Energy Regulatory Commission orders did not eliminate the potential for speculative "ripple claims," which involve potential claims for refunds from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. Idaho Power's settlement payments in those proceedings have been relatively small to date, but the legal costs of defending the claims over the past decade have been substantial. In recent years, Idaho Power has also been a party to legal proceedings advanced by private parties relating to alleged violations of environmental laws at coal-fired plants. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have a negative effect on their financial condition and results of operations. Similarly, the terms of resolution could require the companies to change their business practices and procedures, which could also have a negative affect on their financial positions and results of operations.

Acts or threats of terrorism, cyber attacks, security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations, or the businesses of third parties, could negatively impact IDACORP's and Idaho Power's financial condition and results of operations.  Idaho Power's generation and transmission facilities are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups.  Some of Idaho Power's facilities are deemed "critical infrastructure," in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk electric power system, national economic security, national public health or safety, or any combination of those matters. The possibility that infrastructure facilities, such as generation facilities and electric transmission facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack (whether originating internally or externally) may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power and by delaying the development and construction of new generating and transmission facilities and capital improvements to existing facilities.  These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure Idaho Power's assets, and could further adversely affect Idaho Power's operations by contributing to disruption of supplies and markets for natural gas or coal used to fuel gas- or coal-fired power plants.  

In the normal course of business, Idaho Power collects, processes, and retains sensitive and confidential customer and proprietary information, and operates systems that directly impact the availability of electric power and the transmission of electric power in the electric grid.  Despite the security measures in place, Idaho Power's facilities and systems could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, exposing Idaho Power to liability.  Those breaches and events may result from acts of Idaho Power employees, contractors, or third parties. If Idaho Power's information technology and security systems were to fail or be breached and Idaho Power were unable to recover the systems and/or data in a timely manner, Idaho Power may be unable to fulfill critical business functions. In such case, confidential and proprietary business, employee, or customer information could be compromised, exposing Idaho Power to liability and causing business disruptions, which could negatively affect Idaho Power's business operations and IDACORP's and Idaho Power's financial condition and results of operations.


26


Idaho Power's business and operations may be adversely affected by its inability to successfully implement information technology projects. Idaho Power has undertaken several multi-year company-wide information technology solution upgrades intended to replace existing software and systems, some of which have been completed and some of which are ongoing or in early stages. These projects include a new customer information system implemented in 2013, Idaho Power's SmartGrid initiative, and the current migration from Idaho Power's existing mainframe system to an open system. Idaho Power is also implementing systems to augment and improve its ability to pinpoint the sources of electric system outages, respond to them more quickly, and focus repair efforts. Implementation of these information systems and technology solutions is complex, expensive, and time consuming. If Idaho Power does not successfully implement the new systems and processes, or if the systems do not operate as intended or cause data or operational errors, it could result in substantial disruptions to Idaho Power's business, which could have a material adverse effect on IDACORP's and Idaho Power's results of operations and financial condition.

Changes in tax laws and regulations, or differing interpretation or enforcement of applicable laws by the Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP’s or Idaho Power’s financial condition and results of operations.  IDACORP and Idaho Power must make judgments and interpretations about the application of the law when determining the provision for taxes.  The companies’ tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation, and employment-related taxes and ongoing issues related to these taxes.  These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by taxing authorities.  In recent years, tax settlements, as well as state regulatory mechanisms with tax-related provisions (such as Idaho Power's December 2011 settlement with the Idaho Public Utilities Commission), have significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of ongoing and future income tax proceedings, or the state public utility commissions' treatment of those tax outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect IDACORP’s and Idaho Power’s earnings and cash flows.  Further, in some instances the treatment from a ratemaking perspective of any tax benefits could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations. 

Changes in accounting standards or Securities and Exchange Commission rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board and the Securities and Exchange Commission may make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the Federal Energy Regulatory Commission could significantly impact IDACORP's and Idaho Power's reported financial condition. Idaho Power meets conditions under generally accepted accounting principles to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities.  Idaho Power expects to recover its regulatory assets from customers through rates but recovery is subject to review by the regulatory bodies.  If recovery of these amounts ceases to be probable, 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 required to eliminate some or all of those regulatory assets or liabilities.  Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s financial condition and results of operations.

ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
None.

ITEM 2.  PROPERTIES
 
Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include generation, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants. In addition to these physical assets, Idaho Power has rights-of-way and water rights that enable it to use its facilities. Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon.  As of December 31, 2013, the system also includes approximately 4,856 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 228 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 26,817 pole-miles of distribution lines.
 

27


Idaho Power holds FERC licenses for all of its hydroelectric projects that are subject to federal licensing.  Relicensing of Idaho Power’s hydroelectric projects is discussed in Item 7 - “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.” Idaho Power's hydroelectric projects and other owned and co-owned generating facilities and their nameplate capacities are listed below.
Project
 
Nameplate Capacity (kW)(1)
 
License Expiration
Hydroelectric Projects:
 
 

 
 
 
Properties Subject to Federal Licenses:
 
 

 
 
 
Lower Salmon
 
60,000

 
2034
 
Bliss
 
75,000

 
2034
 
Upper Salmon
 
34,500

 
2034
 
Shoshone Falls
 
12,500

 
2034
 
CJ Strike
 
82,800

 
2034
 
Upper Malad - Lower Malad
 
21,770

 
2035
 
Brownlee - Oxbow - Hells Canyon (Hells Canyon Complex)
 
1,166,900

 
2005
(2) 
Swan Falls
 
27,170

 
2042
 
American Falls
 
92,340

 
2025
 
Cascade
 
12,420

 
2031
 
Milner
 
59,448

 
2038
 
Twin Falls
 
52,897

 
2040
 
Other Hydroelectric:
 
 

 
 
 
Clear Lakes - Thousand Springs
 
11,300

 
 
 
Total Hydroelectric
 
1,709,045

 
 
 
Steam and Other Generating Plants:
 
 

 
 
 
Jim Bridger (coal-fired)(3)
 
770,501

 
 
 
North Valmy (coal-fired)(3)
 
283,500

 
 
 
Boardman (coal-fired)(3)(4)
 
64,200

 
 
 
Danskin (gas-fired)
 
270,900

 
 
 
Langley Gulch (gas-fired)
 
318,452

 
 
 
Bennett Mountain (gas-fired)
 
172,800

 
 
 
Salmon (diesel-internal combustion)
 
5,000

 
 
 
Total Steam and Other
 
1,885,353

 
 
 
Total Generation
 
3,594,398

 
 
 
(1) Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.
(2) Licensed on an annual basis while the application for a new multi-year license is pending.
(3) Idaho Power’s ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy, and 10 percent for Boardman.  Amounts shown represent Idaho Power’s share.
(4) Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.

IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarter campus is comprised of approximately 306,000 square feet of owned office space and approximately 51,000 square feet of leased office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 600,000 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon.

Idaho Power owns all of its interests in principal plants and other important units of real property, except for portions of certain projects licensed under the FPA and reservoirs and other easements.  Substantially all of Idaho Power’s property is subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses.  Idaho Power’s property is subject to minor defects common to properties of such size and character that it believes do not materially impair the value to, or the use by, Idaho Power of such properties.  Idaho Power considers its properties to be well-maintained and in good operating condition.
 
IERCo owns a one-third interest in BCC and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West holds 50-percent interests in nine hydroelectric plants that have a total generating capacity of 45 MW.  These plants are located in Idaho and California.


28


ITEM 3.  LEGAL PROCEEDINGS
 
Refer to Note 10 – “Contingencies” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report.

ITEM 4.  MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report.
PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
 
IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE).  On February 14, 2014, there were 11,370 holders of record of IDACORP common stock and the closing stock price was $54.23 per share.  The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded.  IDACORP became the holding company of Idaho Power on October 1, 1998.
 
The amount and timing of dividends paid on IDACORP’s common stock are within the sole discretion of IDACORP’s board of directors.  The board of directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, 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. At its November 2011 meeting, the IDACORP board of directors adopted a dividend policy for IDACORP 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 the board of director's dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will take into account the foregoing factors, among others.
 
A covenant under IDACORP’s credit facility and Idaho Power’s credit facility described in Part II, Item 7 - “MD&A – Liquidity and Capital Resources - Financing Programs and Available Liquidity – IDACORP and Idaho Power Credit Facilities” requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined in the respective credit facilities, of no more than 65 percent at the end of each fiscal quarter.
 
Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.  Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct.  At December 31, 2013, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $945 million and $848 million, respectively, at December 31, 2013.  Idaho Power must obtain approval of the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.
 
Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears.  Idaho Power has no preferred stock outstanding.  IDACORP and Idaho Power paid dividends of $79 million, $69 million, and $60 million in 2013, 2012, and 2011, respectively.

On September 19, 2013, IDACORP's board of directors voted to increase the quarterly dividend to $0.43 per share of IDACORP common stock, from the prior dividend amount of $0.38 per share of IDACORP common stock, commencing with the dividend payable December 2, 2013. For additional information relating to IDACORP and Idaho Power dividends, including 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.
 

29


The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2013 and 2012 as reported by the NYSE.
 
 
2013
 
2012
Quarter
 
High
 
Low
 
Dividends paid per share
 
High
 
Low
 
Dividends paid per share
1st
 
$
48.53

 
$
43.13

 
$
0.38

 
$
42.89

 
$
39.66

 
$
0.33

2nd
 
50.16

 
46.03

 
0.38

 
42.22

 
38.17

 
0.33

3rd
 
54.74

 
45.62

 
0.38

 
44.03

 
41.00

 
0.33

4th
 
53.99

 
47.57

 
0.43

 
45.67

 
40.18

 
0.38


During 2013, 2012, and 2011, Idaho Power paid dividends to its parent, IDACORP, in the amounts shown in Idaho Power's Consolidated Statements of Retained Earnings included in this report.

IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2013.
 
Performance Graph
 
The following performance graph shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index, and the Edison Electric Institute (EEI) Electric Utilities Index.  The data assumes that $100 was invested on December 31, 2008, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.
Source:  Bloomberg and EEI
 
 
2008
 
2009
 
2010
 
2011
 
2012
 
2013
IDACORP
 
$
100.00

 
$
113.55

 
$
136.09

 
$
160.93

 
$
170.06

 
$
210.04

S&P 500
 
100.00

 
126.45

 
145.52

 
148.55

 
172.29

 
228.04

EEI Electric Utilities Index
 
100.00

 
110.71

 
118.50

 
142.18

 
145.15

 
164.03


The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and should not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.

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ITEM 6.  SELECTED FINANCIAL DATA
IDACORP, Inc.(1)
SUMMARY OF OPERATIONS
(thousands of dollars, except per share amounts and statistics)
 
 
2013
 
2012
 
2011
 
2010
 
2009
Operating revenues
 
$
1,246,214

 
$
1,080,662

 
$
1,026,756

 
$
1,036,029

 
$
1,049,800

Operating income
 
291,742

 
242,602

 
155,352

 
191,811

 
196,363

Net income attributable to IDACORP, Inc.
 
182,417

 
173,014

 
169,981

 
145,018

 
126,384

Diluted earnings per share
 
3.64

 
3.46

 
3.43

 
3.00

 
2.68

Dividends declared per share
 
1.57

 
1.37

 
1.20

 
1.20

 
1.20

 
 
 
 
 
 
 
 
 
 
 
Financial Condition:
 
 
 
 
 
 
 
 
 
 
Total assets
 
5,364,563

 
5,291,290

 
4,925,319

 
4,635,304

 
4,194,287

Long-term debt (including current portion)
 
1,616,322

 
1,537,696

 
1,488,614

 
1,610,859

 
1,419,070

 
 
 
 
 
 
 
 
 
 
 
Financial Statistics:
 
 
 
 
 
 
 
 
 
 
Times interest charges earned:
 
 
 
 
 
 
 
 
 
 
Before tax(2)
 
3.87

 
3.41

 
2.48

 
2.78

 
3.02

After tax(3)
 
3.06

 
3.02

 
3.00

 
2.69

 
2.62

Book value per share(4)
 
$
36.84

 
$
34.73

 
$
32.76

 
$
30.51

 
$
28.62

Market-to-book ratio(5)
 
141
%
 
125
%
 
129
%
 
121
%
 
112
%
Payout ratio(6)
 
43
%
 
40
%
 
35
%
 
40
%
 
45
%
Return on year-end common equity(7)
 
9.9
%
 
9.9
%
 
10.4
%
 
9.6
%
 
9.2
%
 
 
 
 
 
 
 
 
 
 
 
(1) All previously reported Net income attributable to IDACORP, Inc., Diluted earnings per share amounts, Total assets, Times interest charges earned, Book value per share, Market-to-book ratio, Payout ratio, and Return on year-end common equity have been adjusted to reflect the adoption of ASU 2014-01. See Note 1 to the consolidated financial statements included in this report.
The financial statistics listed above are calculated in the following manner:
(2) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
(3) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income from continuing operations divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
(4) Total equity, excluding non-controlling interests, at the end of the year divided by shares outstanding at the end of the year.
(5) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in footnote (3) above.
(6) Dividends paid per common share divided by diluted earnings per share.
(7) Net income attributable to IDACORP, Inc. divided by total equity, excluding non-controlling interests, at the end of the year.


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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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


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


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


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 Power Plant
Request for recovery of and return on Idaho Power's investment in the Langley Gulch power plant, including operating costs
IPUC approved a $58.1 million increase in rates, effective July 1, 2012; OPUC approved a $3.0 million increase in rates effective October 1, 2012
Idaho Jurisdiction Power Cost Adjustment (PCA) - 2012
Annual Idaho-jurisdiction PCA mechanism rate change
IPUC approved a $43.0 million increase in PCA rates, effective for the period from June 1, 2012 to May 31, 2013
2011 Revenue Sharing
Rate adjustment pursuant to January 2010 settlement agreement
IPUC approved using $27.1 million of sharing to reduce PCA rates.
Idaho Jurisdiction PCA - 2013
Annual Idaho-jurisdiction PCA mechanism rate change
IPUC approved a $121.3 million net increase in PCA rates, effective for the period from June 1, 2013 to May 31, 2014
2012 Revenue Sharing
Rate adjustment pursuant to December 2011 settlement agreement
IPUC approved using $7.2 million of sharing against PCA rates, effective for the period from June 1, 2013 to May 31, 2014
Depreciation for Non-AMI Meters
Application for removal from rates of accelerated depreciation expense associated with non-advanced metering infrastructure (AMI) metering equipment
IPUC approved a $10.6 million decrease in rates and associated depreciation expense, effective June 1, 2012

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


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


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


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


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


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


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 AFUDC(1)
 
(10,776
)
 
(10,636
)
 
(10,636
)
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.

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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

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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.


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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.


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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.



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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.


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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 approximatel