Edgar Filing: AVISTA CORP

AVA-2012.12.31-10K

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, 2012 OR



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-3701

__________________________________________________________________________________________

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)



Washington		91-0462470
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1411 East Mission Avenue, Spokane, Washington		99202-2600
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: 509-489-0500

Web site: http://www.avistacorp.com

Securities registered pursuant to Section 12(b) of the Act:



Title of Class		Name of Each Exchange on Which Registered
Common Stock, no par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

Preferred Stock, Cumulative, Without Par Value

__________________________________________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has 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 Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s 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

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ¨ No x

The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,568,836,865 based on the last reported sale price thereof on the consolidated tape on June 30, 2012.

As of January 31, 2013, 59,851,338 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

__________________________________________________________________________________________

Documents Incorporated By Reference



Document		Part of Form 10-K into Which Document is Incorporated
Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 9, 2013		Part III, Items 10, 11, 12, 13 and 14

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INDEX



Item No.		Page No.
	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	3
	Part I
1	Business	4
	Company Overview	4
	Avista Utilities	5
	General	5
	Electric Operations	5
	Electric Requirements	5
	Electric Resources	6
	Hydroelectric Licensing	7
	Future Resource Needs	8
	Natural Gas Operations	9
	Regulatory Issues	10
	Federal Laws Related to Wholesale Competition	11
	Regional Transmission Organizations	11
	Reliability Standards	12
	Avista Utilities Operating Statistics	13
	Ecova	16
	Other Businesses	17
1A.	Risk Factors	18
1B.	Unresolved Staff Comments	22
2	Properties	23
	Avista Utilities	23
3	Legal Proceedings	24
4	Mine Safety Disclosures	24	*
	Part II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
6	Selected Financial Data	25
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Business Segments	27
	Executive Level Summary	27
	Avista Utilities – Regulatory Matters	29
	Results of Operations	34
	Avista Utilities	36
	Ecova	42
	Other Businesses	43
	Accounting Standards to Be Adopted in 2013	43
	Critical Accounting Policies and Estimates	43
	Liquidity and Capital Resources	46
	Review of Cash Flow Statement	46
	Overall Liquidity	47
	Collateral Requirements	48
	Dodd-Frank Wall Street Reform and Consumer Protection Act	48
	Capital Resources	49
	Avista Utilities Capital Expenditures	50
	Ecova Credit Agreement	51
	Ecova Redeemable Stock	51
	Off-Balance Sheet Arrangements	52
	Pension Plan	52
	Credit Ratings	52
	Dividends	52
	Contractual Obligations	53
	Competition	54

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	Economic Conditions and Utility Load Growth	54
	Environmental Issues and Other Contingencies	55
7A.	Quantitative and Qualitative Disclosures about Market Risk	58
8.	Financial Statements and Supplementary Data	65
	Report of Independent Registered Public Accounting Firm	66
	Financial Statements	67
	Consolidated Statements of Income	67
	Consolidated Statements of Comprehensive Income	68
	Consolidated Balance Sheets	69
	Consolidated Statements of Cash Flows	71
	Consolidated Statements of Equity and Redeemable Noncontrolling Interests	73
	Notes to Consolidated Financial Statements	74
	Note 1. Summary of Significant Accounting Policies	74
	Note 2. New Accounting Standards	82
	Note 3. Variable Interest Entities	82
	Note 4. Voluntary Severance Incentive Program	83
	Note 5. Redeemable Noncontrolling Interests and Subsidiary Acquisitions	84
	Note 6. Derivatives and Risk Management	85
	Note 7. Jointly Owned Electric Facilities	89
	Note 8. Property, Plant and Equipment	89
	Note 9. Asset Retirement Obligations	90
	Note 10. Pension Plans and Other Postretirement Benefit Plans	91
	Note 11. Accounting for Income Taxes	96
	Note 12. Energy Purchase Contracts	98
	Note 13. Short-Term Borrowings	99
	Note 14. Long-Term Debt	100
	Note 15. Long-Term Debt to Affiliated Trusts	101
	Note 16. Leases	102
	Note 17. Fair Value	102
	Note 18. Common Stock	107
	Note 19. Earnings per Common Share Attributable to Avista Corporation Shareholders	107
	Note 20. Stock Compensation Plans	108
	Note 21. Commitments and Contingencies	111
	Note 22. Information Services Contracts	116
	Note 23. Avista Utilities Regulatory Matters	117
	Note 24. Information by Business Segments	122
	Note 25. Selected Quarterly Financial Data (Unaudited)	124
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	124	*
9A.	Controls and Procedures	124
9B.	Other Information	127
	Part III
10.	Directors, Executive Officers and Corporate Governance	127
11.	Executive Compensation	128
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	128
13.	Certain Relationships and Related Transactions, and Director Independence	129
14.	Principal Accounting Fees and Services	129
	Part IV
15.	Exhibits, Financial Statement Schedules	130
	Signatures	131
	Exhibit Index	133

* = not an applicable item in the 2012 calendar year for Avista Corp.

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ACRONYMS AND TERMS

(The following acronyms and terms are found in multiple locations within the document)



Acronym/Term	Meaning
aMW	-	Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
AFUDC	-	Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
AM&D	-	Advanced Manufacturing and Development, does business as METALfx
ASC	-	Accounting Standards Codification
Avista Capital	-	Parent company to the Company’s non-utility businesses
Avista Corp.	-	Avista Corporation, the Company
Avista Energy	-	Avista Energy, Inc., an electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital. This entity is currently inactive; however, we still incur legal fees associated with this entity.
Avista Utilities	-	Operating division of Avista Corp. comprising the regulated utility operations
BPA	-	Bonneville Power Administration
Capacity	-	The rate at which a particular generating source is capable of producing energy, measured in KW or MW
Cabinet Gorge	-	The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
Colstrip	-	The coal-fired Colstrip Generating Plant in southeastern Montana
Coyote Springs 2	-	The natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon
CT	-	Combustion turbine
Deadband or ERM deadband	-	The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the Energy Recovery Mechanism in the state of Washington
Dekatherm	-	Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy)
Ecology	-	The state of Washington’s Department of Ecology
Ecova	-	Ecova, Inc., a provider of facility information and cost management services for multi-site customers and energy efficiency program management for commercial enterprises and utilities throughout North America, subsidiary of Avista Capital. Formerly known as Advantage IQ, Inc. (Advantage IQ)
Energy	-	The amount of electricity produced or consumed over a period of time, measured in KWH or MWH. Also, refers to natural gas consumed and is measured in dekatherms.
EPA	-	Environmental Protection Agency
ERM	-	The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
GAAP	-	Generally Accepted Accounting Principles
GHG	-	Greenhouse gas
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
Jackson Prairie	-	Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington
kV	-	Kilovolt (1000 volts): a measure of capacity on transmission lines
KW, KWH	-	Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced
Lancaster Plant	-	A natural gas-fired combined cycle combustion turbine plant located in Idaho
MW, MWH	-	Megawatt: 1000 KW. Megawatt-hour: 1000 KWH
NERC	-	North American Electricity Reliability Corporation

iii

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Noxon Rapids	-	The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
OPUC	-	The Public Utility Commission of Oregon
PCA	-	The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho
PGA	-	Purchased Gas Adjustment
PLP	-	Potentially liable party
PUD	-	Public Utility District
PURPA	-	The Public Utility Regulatory Policies Act of 1978, as amended
RTO	-	Regional Transmission Organization
Spokane Energy	-	Spokane Energy, LLC, a special purpose limited liability company and all of its membership capital is owned by Avista Corp.
Spokane River Project	-	The five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls)
Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
UTC	-	Washington Utilities and Transportation Commission
Watt	-	Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt

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Forward-Looking Statements

From time to time, we make forward-looking statements such as statements regarding projected or future:


•	financial performance,


•	cash flows,


•	capital expenditures,


•	dividends,


•	capital structure,


•	other financial items,


•	strategic goals and objectives,


•	business environment, and


•	plans for operations.

These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and they could have a significant effect on our operations, results of operations, financial condition or cash flows. This could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:


•	weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;


•	state and federal regulatory decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments and operating costs;


•	changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;


•	economic conditions in our service areas, including customer demand for utility services;


•	the effect of increased customer energy efficiency;


•	our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy;


•	the potential effects of legislation or administrative rulemaking, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;


•	changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement medical plans, which can affect future funding obligations, pension and other postretirement medical expense and pension and other postretirement medical plan liabilities;


•	volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales;


•	the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible refunds;


•	the outcome of legal proceedings and other contingencies;


•	changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs;

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•	wholesale and retail competition including alternative energy sources, suppliers and delivery arrangements and the extent that new uses for our services may materialize;


•	the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels;


•	severe weather or natural disasters that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;


•	explosions, fires, accidents, mechanical breakdowns, or other incidents that may cause unplanned outages at any of our generation facilities, transmission and distribution systems or other operations;


•	public injuries or damages arising from or allegedly arising from our operations;


•	blackouts or disruptions of interconnected transmission systems (the regional power grid);


•	disruption to information systems, automated controls and other technologies that we rely on for operations, communications and customer service;


•	terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems;


•	delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;


•	changes in the costs to implement new information technology systems and/or obstacles that impede our ability to complete such projects timely and effectively;


•	changes in the long-term climate of the Pacific Northwest, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;


•	changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers;


•	the loss of key suppliers for materials or services;


•	default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy;


•	deterioration in the creditworthiness of our customers;


•	potential decline in our credit ratings, with effects including impeded access to capital markets, higher interest costs, and certain ratings trigger covenants in our financing arrangements and wholesale energy contracts;


•	increasing health care costs and the resulting effect on health insurance provided to our employees and retirees;


•	increasing costs of insurance, more restricted coverage terms and our ability to obtain insurance;


•	work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;


•	the potential effects of negative publicity regarding business practices - whether true or not - which could result in litigation or a decline in our common stock price;


•	changes in technologies, possibly making some of the current technology obsolete;


•	changes in tax rates and/or policies;


•	changes in the payment acceptance policies of Ecova’s client vendors that could reduce operating revenues;


•	potential difficulties for Ecova in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; and


•	changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to

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update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

Available Information

Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available at our Web site as soon as practicable after electronically filing these reports with the Securities and Exchange Commission. Information contained on our Web site is not part of this report.

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PART I

Item 1. Business

Company Overview

Avista Corporation (Avista Corp. or the Company), incorporated in the state of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. As of December 31, 2012, we employed 1,682 people in our utility operations (prior to the voluntary severance incentive program, which resulted in the termination of 55 employees effective at the end of the day on December 31, 2012) and 1,497 people in our subsidiary businesses. See "Note 4 of the Notes to Consolidated Financial Statements" for further discussion of the voluntary severance incentive program. Our corporate headquarters are in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. The Inland Northwest also coincides closely with our utility service area in Washington and Idaho. Our gas utility operations also include separate service areas in southwestern Oregon.

We have two reportable business segments as follows:


•	Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

•

Ecova – an indirect subsidiary of Avista Corp. (79.0 percent owned as of December 31, 2012) provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova’s service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.

We have other businesses, including a sheet metal fabrication business, emerging technology venture fund investments and commercial real estate investments, as well as Spokane Energy, LLC (Spokane Energy). These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp.

Ecova and various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Total Avista Corp. stockholders’ equity was $1,259.5 million as of December 31, 2012, of which $118.7 million represented our investment in Avista Capital. Additionally, Ecova represents $73.9 million of our investment in Avista Capital.

See “Item 6. Selected Financial Data” and “Note 24 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).

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Avista Utilities

General

Through our regulated utility operations, we generate, transmit and distribute electricity and distribute natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. We also engage in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.

Our utility provides electric distribution and transmission, as well as natural gas distribution services in parts of eastern Washington and northern Idaho. We also provide natural gas distribution service in parts of northeastern and southwestern Oregon. At the end of 2012, we supplied retail electric service to 362,000 customers and retail natural gas service to 323,000 customers across our entire service territory. Our service territory covers 30,000 square miles with a population of 1.5 million. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory.

Electric Operations

In addition to providing electric distribution and transmission services, we generate electricity from facilities that we own and we purchase capacity and energy and fuel for generation under long-term and short-term contracts. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below.

As part of our resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and the use of these resources to capture available economic value. We transact business in the wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, transport and fuel. Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. We make continuing projections of:


•	electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and


•	resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience.

On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:


•	purchasing fuel for generation,


•	when economical, selling fuel and substituting wholesale electric purchases, and


•	other wholesale transactions to capture the value of generation and transmission resources and fuel delivery (transport) capacity contracts.

Our optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments.

Our generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Transmission revenues were $12.7 million in 2012, $13.8 million in 2011 and $12.8 million in 2010.

Electric Requirements

Our peak electric native load requirement for 2012 occurred on August 7, 2012 at which time our total obligation was 2,485 MW consisting of:


•	native load of 1,579 MW,

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•	long-term wholesale obligations of 236 MW, and


•	short-term wholesale obligations of 670 MW.

At that time our maximum resource capacity available was 3,060 MW, which included:


•	company-owned or controlled electric generation of 1,755 MW,


•	long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 152 MW,


•	long-term thermal generation contract with Lancaster Plant of 270 MW,


•	other long-term wholesale contracts of 133 MW, and


•	short-term wholesale purchases of 750 MW.

Historically, our peak electric native load requirement has occurred during the winter months; however, due to a weather anomaly in 2012, the peak electric native load requirement occurred during the summer period. We expect our peak electric native load requirement to occur in winter periods in the future.

Electric Resources

We have a diverse electric resource mix of Company-owned and contracted hydroelectric projects, thermal generating facilities, wind generation facilities, and power purchases and exchanges.

At the end of 2012, our Company-owned facilities had a total net capability of 1,844 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities.

Hydroelectric Resources We own and operate six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is our lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2013 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 534 average megawatts (aMW) (or 4.7 million MWhs). Hydroelectric resources provided 583 aMW for 2012, 637 aMW for 2011 and 477 aMW for 2010.

The following table shows our hydroelectric generation (in thousands of MWhs) during the year ended December 31:



	2012	2011	2010
Noxon Rapids	1,823	2,110	1,503
Cabinet Gorge	1,199	1,292	942
Post Falls	83	90	90
Upper Falls	60	73	71
Monroe Street	102	110	106
Nine Mile	106	90	101
Long Lake	513	556	480
Little Falls	202	213	201
Total company-owned hydroelectric generation	4,088	4,534	3,494
Long-term hydroelectric contracts with PUDs	1,022	1,047	685
Total hydroelectric generation	5,110	5,581	4,179

Thermal Resources We own:


•	the combined cycle combustion turbine (CT) natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon,


•	a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana,


•	a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington,

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•	a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT),


•	a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and


•	two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT).

Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.

Colstrip, which is operated by PPL Montana, LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019.

The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

See "Item 2 Properties - Avista Utilities - Generation Properties" for the nameplate rating and present generating capabilities of the above thermal resources.

The following table shows our thermal generation (in thousands of MWhs) during the year ended December 31:



	2012	2011	2010
Coyote Springs 2	1,142	705	1,661
Colstrip	1,499	1,433	1,749
Kettle Falls GS	209	291	312
Northeast CT and Rathdrum CT	7	8	12
Boulder Park and Kettle Falls CT	7	10	14
Total company-owned thermal generation	2,864	2,447	3,748
Long-term contract with Lancaster Plant	1,208	835	1,410
Total thermal generation	4,072	3,282	5,158

Lancaster Plant Power Purchase Agreement The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to us through 2026 under a power purchase agreement (PPA).

Palouse Wind PPA In June 2011, we entered into a 30-year PPA with Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC. Under the PPA, we acquire all of the power and renewable attributes produced by a wind project that was developed by Palouse Wind in Whitman County, Washington. The wind project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 aMW. The project was completed and deliveries began during the fourth quarter of 2012. Generation from Palouse Wind was 61,450 MWhs in 2012. We have an annual option to purchase the wind project following the 10^th anniversary of its December 2012 commercial operation date.

Other Purchases, Exchanges and Sales In addition to the resources described above, we purchase and sell power under various long-term contracts and we also enter into short-term purchases and sales. Further, pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA), as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC). Existing PURPA contracts expire at various times through 2022.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2012, 2011 and 2010. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see "Future Resource Needs" for the magnitude of these power purchase and sales contracts in future periods.

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Hydroelectric Licensing

We are a licensee under the Federal Power Act as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project, our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.

The Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids) are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 21 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway and our mitigation plans and efforts.

Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls) are under one 50-year FERC license issued in June 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. For further information see “Spokane River Licensing” in “Note 21 of the Notes to Consolidated Financial Statements.”

Future Resource Needs

We have operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,075 aMW in 2012, 1,096 aMW in 2011 and 1,075 aMW in 2010. The following is a forecast of our average annual energy requirements and resources for 2013, 2014, 2015 and 2016:

Forecasted Electric Energy Requirements and Resources

(aMW)



	2013	2014	2015	2016
Requirements:
System load (1)	1,067	1,054	1,067	1,079
Contracts for power sales	128	109	58	49
Total requirements	1,195	1,163	1,125	1,128
Resources:
Company-owned and contract hydro generation (2)	534	535	504	504
Company-owned and contract thermal generation (3)	704	704	725	718
Other contracts for power purchases	194	162	161	160
Total resources	1,432	1,401	1,390	1,382
Surplus resources	237	238	265	254
Additional available energy (4)	149	153	139	154
Total surplus resources	386	391	404	408


(1)	System load is reduced in 2013 because a large industrial customer will begin generating electricity to meet a portion of its own load after June 30, 2013. The full impact of this load change culminates in 2014 when load is reduced for 12 calendar months.


(2)	The forecast assumes near normal hydroelectric generation (decline in 2015 and 2016 is due to changes in contracts with PUDs).


(3)	Includes our long-term contract with the Lancaster Plant. Excludes Northeast CT and Rathdrum CT as these are considered peaking facilities and are generally not used to meet our base load requirements. We generally dispatch thermal resources when operating costs are lower than short-term wholesale market prices.


(4)	Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

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In August 2011, we filed our 2011 Electric Integrated Resource Plan (IRP) with the UTC and the IPUC. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2011 IRP include:


•	A contract for the 105 MW Palouse Wind, LLC project, which provides a new resource to serve our customers’ increasing energy needs. Commercial operations began on December 13, 2012.


•	An additional 42 aMW of wind or other renewable beginning in 2021.


•	Energy efficiency measures are expected to save 310 aMW of cumulative energy over the 20-year IRP timeframe. This aggressive effort could reduce load growth to half of what it would be without these measures.


•	750 MW of new natural gas-fired generation facilities are anticipated in two or three increments between 2018 and 2031.


•	Grid modernization programs are projected to save 5 aMW of energy by 2013.


•	Transmission upgrades will be needed to deliver the energy from new generation resources to the distribution lines serving customers. We will continue to participate in regional efforts to expand the region’s transmission system.

We are required to file an IRP every two years with the next IRP expected to be filed during the third quarter of 2013. Our resource strategy may change from the 2011 IRP based on market, legislative and regulatory developments, etc.

We are subject to the Washington state Energy Independence Act, which includes renewable energy portfolio standards and we must obtain a portion of our electricity from qualifying renewable resources or through purchase of renewable energy credits. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix.

Natural Gas Operations

General We provide natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon.

Market prices for natural gas, like other commodities, can be volatile. To provide reliable supply and to manage the impact of volatile prices on our customers, we procure natural gas through a diversified mix of spot market purchases, forward fixed price purchases, and derivative instruments from various supply basins and over various time periods. We also use natural gas storage capacity to support high demand periods and to procure natural gas when prices may be seasonally lower. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

Natural gas loads are highly variable and daily natural gas loads can differ significantly from the monthly load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. On the basis of these projections, we plan and execute a series of transactions to hedge a significant portion of our projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future with the highest volumes hedged for the current and most immediate upcoming natural gas operating year (November through October). We also leave a significant portion of our natural gas supply requirements unhedged for purchase in short-term and spot markets.

As part of the process of balancing natural gas retail load requirements with resources, we engage in wholesale purchases and sales of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers on a theoretical peak day. As such, we generally have more pipeline and storage capacity than what is needed, during periods other than a peak day. We optimize natural gas resources by using market opportunities to generate economic value that partially offsets net natural gas costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system and, when feasible, physical delivery may be avoided through offsetting purchase and sale book-out arrangements. Natural gas resource optimization activities include, but are not limited to:

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•	wholesale market sales of surplus natural gas supplies, and


•	purchases and sales of natural gas to optimize use of pipeline and storage capacity.

We also provide transportation service to certain large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we move their natural gas from natural gas transmission pipeline delivery points through our distribution system to the customers’ premises.

Natural Gas Supply We purchase all of our natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and western Canada through firm capacity delivery rights on six pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline delivery rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources, and 75 percent from Canadian sources. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our source mix to vary.

Natural Gas Storage We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. Our share of the peak day deliverability and total working capacity is one-third of these.

Natural gas storage enables us to place natural gas into storage when prices may be lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Natural Gas Pipeline Replacement In 2011, we began implementation of a plan to replace certain vintages of Aldyl A natural gas pipe within its distribution systems in Washington, Oregon and Idaho. In early 2012, we released our protocol report to each state Commission describing our Aldyl A natural gas pipe replacement plan across its natural gas system. Later in 2012, after technical workshops held by the UTC to gather perspectives on pipeline replacement programs, including the need for expedited cost recovery, the UTC required all natural gas utilities operating in Washington to file applicable replacement plans with the Commission. We subsequently filed our protocol report with the UTC proposing to replace our Aldyl A natural gas pipe at a cost of approximately $10 million per year, indexed to inflation, across our three state jurisdictions over a 20-year period. We expect to receive cost recovery for these capital expenditures from the three jurisdictions over the subsequent future life of these assets.

Regulatory Issues

General As a public utility, we are subject to regulation by state utility commissions for prices, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the UTC, the IPUC, the Public Utility Commission of Oregon (OPUC), and the Public Service Commission of the State of Montana (Montana Commission). Approval of the issuance of securities is not required from the Montana Commission. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis.

Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned among five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, a request for new rates in Washington and Idaho is made on the basis of net investment as of a date, and operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments designed to reflect expected revenues, expenses and net investment during the period new retail rates will be in effect. Although the current ratemaking process in these states provides recovery of some future changes in net investment, operating costs and revenues, it does not reflect all changes in costs for the period in which new retail rates will be in place. This historically has resulted in a lag between the time we incur costs and the time when we start recovering the costs through subsequent changes in rates. Oregon currently allows a forecasted test year, which generally is more effective in providing timely recovery of costs.

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Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Notes 1 and 23 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes.

General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – General Rate Cases” for information on general rate case activity.

Power Cost Deferrals We defer the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the UTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for detailed information on power cost deferrals and recovery mechanisms in Washington and Idaho.

Purchased Gas Adjustment (PGA) Under established regulatory practices in each state, we are allowed to adjust natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs included in retail rates are deferred during the period the differences are incurred. During the subsequent period when regulators approve inclusion of the cost changes in rates, any amounts that were previously deferred are charged or credited to expense. We typically propose such PGAs at least once per year. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Purchased Gas Adjustments” and “Note 23 of the Notes to Consolidated Financial Statements” for detailed information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.

Federal Laws Related to Wholesale Competition

Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.

Public utilities operating under the Federal Power Act are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Competition” for further information.

Regional Transmission Organizations

Beginning with FERC Orders No. 888 and No. 2000 (issued in 2000) and continuing with subsequent rulemakings and policies (including the Variable Energy Resource Order No. 764 and the Transmission Planning and Cost Allocation Order No. 1000), the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) such as an independent system operator (ISO). While it has not mandated RTO formation, the FERC has issued orders and made public policy statements indicating its support for the development and formation of independent organizations, including those intended to implement a number of regional transmission planning coordination requirements.

We have participated in discussions with transmission providers and other stakeholders in the Pacific Northwest for several years regarding the possible formation of an ISO in the region. ColumbiaGrid is a Washington nonprofit membership corporation with an independent slate of directors formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest and we became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs limited functions as set forth in specific agreements with ColumbiaGrid members and other stakeholders, and fills the role of coordinating Avista's regional planning as required in Order No. 1000 and any clarifying Orders. ColumbiaGrid and its members also work with other western organizations to address operational efficiencies, including WestConnect and the Northern Tier Transmission Group (NTTG). We became a registered Planning

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Participant of the NTTG during 2011. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives.

The FERC requires RTOs to provide various data and is currently requesting non-RTO regions to report similar data for the purpose of establishing performance metrics. We expect the FERC to use this data to compare RTO and non-RTO regions. We cannot foresee what policy objectives the FERC may develop as a result of establishing such performance metrics.

Reliability Standards

Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess fines for non-compliance with these standards and other FERC regulations.

The FERC certified the North American Electricity Reliability Corporation (NERC) as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC has approved NERC Reliability Standards, including western region standards, making up the set of legally enforceable standards for the United States’ bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards.

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS



	Years Ended December 31,
	2012			2011			2010
ELECTRIC OPERATIONS
OPERATING REVENUES (Dollars in Thousands):
Residential	$	315,137		$	324,835		$	296,627
Commercial	286,568			280,139			265,219
Industrial	119,589			122,560			114,792
Public street and highway lighting	7,240			6,941			6,702
Total retail	728,534			734,475			683,340
Wholesale	102,736			78,305			165,553
Sales of fuel	115,835			153,470			106,375
Other	21,067			21,937			19,015
Total electric operating revenues	$	968,172		$	988,187		$	974,283
ENERGY SALES (Thousands of MWhs):
Residential	3,608			3,728			3,618
Commercial	3,127			3,122			3,100
Industrial	2,100			2,147			2,099
Public street and highway lighting	26			26			26
Total retail	8,861			9,023			8,843
Wholesale	3,733			2,796			3,803
Total electric energy sales	12,594			11,819			12,646
ENERGY RESOURCES (Thousands of MWhs):
Hydro generation (from Company facilities)	4,088			4,534			3,494
Thermal generation (from Company facilities)	2,864			2,447			3,748
Purchased power - hydro generation from long-term contracts with PUDs	1,022			1,047			685
Purchased power - thermal generation from long-term contracts with Lancaster plant	1,208			835			1,410
Purchased power - wholesale	4,056			3,553			3,905
Power exchanges	(10		)	(24		)	(15		)
Total power resources	13,228			12,392			13,227
Energy losses and Company use	(634		)	(573		)	(581		)
Total energy resources (net of losses)	12,594			11,819			12,646
NUMBER OF RETAIL CUSTOMERS (Average for Period):
Residential	318,692			316,762			315,283
Commercial	39,869			39,618			39,489
Industrial	1,395			1,380			1,376
Public street and highway lighting	503			455			449
Total electric retail customers	360,459			358,215			356,597
RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)	11,323			11,769			11,476
Revenue per KWh (in cents)	8.73			8.71			8.20
Annual revenue per customer	$	988.84		$	1,025.48		$	940.83
AVERAGE HOURLY LOAD (aMW)	1,075			1,096			1,075

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS



	Years Ended December 31,
	2012		2011		2010
REQUIREMENTS AND RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter):
Retail native load	1,554		1,669		1,704
Wholesale obligations	637		712		803
Total requirements (winter)	2,191		2,381		2,507
Total resource availability (winter)	2,618		2,923		2,905
Total requirements (summer):
Retail native load	1,579		1,535		1,556
Wholesale obligations	906		472		822
Total requirements (summer)	2,485		2,007		2,378
Total resource availability (summer)	3,060		2,370		2,662
COOLING DEGREE DAYS: (1)
Spokane, WA
Actual	535		426		380
30-year average	434		434		434
% of average	123	%	98	%	88	%
HEATING DEGREE DAYS: (2)
Spokane, WA
Actual	6,256		6,861		6,320
30-year average	6,676		6,647		6,647
% of average	94	%	103	%	95	%


(1)	Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).


(2)	Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS



	Years Ended December 31,
	2012			2011			2010
NATURAL GAS OPERATIONS
OPERATING REVENUES (Dollars in Thousands):
Residential	$	196,719		$	219,557		$	193,169
Commercial	98,994			111,964			98,257
Interruptible	2,232			2,519			2,738
Industrial	3,635			4,180			3,756
Total retail	301,580			338,220			297,920
Wholesale	158,631			195,882			197,364
Transportation	7,032			6,709			6,470
Other	6,930			7,414			9,495
Total natural gas operating revenues	$	474,173		$	548,225		$	511,249
THERMS DELIVERED (Thousands of Therms):
Residential	189,152			207,202			188,546
Commercial	115,083			125,344			113,422
Interruptible	4,363			4,503			4,443
Industrial	5,073			5,654			5,312
Total retail	313,671			342,703			311,723
Wholesale	586,193			510,755			468,887
Transportation	154,704			152,515			142,093
Interdepartmental and Company use	381			440			393
Total therms delivered	1,054,949			1,006,413			923,096
SOURCES OF NATURAL GAS DELIVERED (Thousands of Therms):
Purchases	919,684			877,290			787,836
Storage - injections	(105,904		)	(109,782		)	(86,750		)
Storage - withdrawals	93,850			94,504			83,333
Natural gas for transportation	154,704			152,515			142,093
Distribution system losses	(7,385		)	(8,114		)	(3,416		)
Total natural gas delivered	1,054,949			1,006,413			923,096
NUMBER OF RETAIL CUSTOMERS (Average for Period):
Residential	286,522			284,504			282,721
Commercial	33,763			33,540			33,431
Interruptible	38			38			38
Industrial	263			255			254
Total natural gas retail customers	320,586			318,337			316,444
RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (therms)	660			728			667
Revenue per therm (in dollars)	$	1.04		$	1.06		$	1.02
Annual revenue per customer	$	686.57		$	771.72		$	683.25

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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS



	Years Ended December 31,
	2012		2011		2010
HEATING DEGREE DAYS: (1)
Spokane, WA
Actual	6,256		6,861		6,320
30-year average	6,676		6,647		6,647
% of average	94	%	103	%	95	%
Medford, OR
Actual	4,182		4,634		4,119
30-year average	4,422		4,402		4,402
% of average	95	%	105	%	94	%


(1)	Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

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Ecova

Ecova provides sustainable utility expense management and energy management solutions to multi-site companies across North America. Ecova’s invoice processing, auditing and payment services, coupled with energy procurement, comprehensive reporting and advanced analysis, provide the critical data clients need to help balance the financial, social and environmental aspects of doing business.

As part of the expense management services, Ecova analyzes and audits invoices, then presents consolidated bills on-line, and processes payments. Information gathered from invoices, providers and other customer-specific data allows Ecova to provide its clients with in-depth analytical support, real-time reporting and consulting services.

Ecova also provides a wide array of energy efficiency program management services to utilities across North America. As part of these management services, Ecova helps utilities develop and execute energy efficiency programs and can provide utilities with a complete turn-key solution.

The following table presents key statistics for Ecova:



	2012		2011		2010
Expense management customers at year-end	740		645		534
Billed sites at year-end	697,076		496,842		360,596
Dollars of customer bills processed (in billions)	$	19.4	$	18.3	$	17.3

Ecova's growth over the last several years in the key statistics listed above can be attributed to a combination of strategic acquisitions, new services and growth among existing customers, additional customers, and a high customer retention rate. On December 31, 2010, Ecova acquired The Loyalton Group, a Minneapolis-based energy management firm that provided energy procurement and price risk management solutions. In January 2011, Ecova acquired Building Knowledge Networks, a Seattle-based real-time building energy management services provider. In November 2011, Ecova acquired Prenova, an energy management company headquartered in Atlanta, Georgia. In January 2012, Ecova acquired LPB Energy Management (LPB), an energy management company headquartered in Dallas, Texas.

The noncontrolling interest of Ecova (which was 21.0 percent as of December 31, 2012) is primarily held by the previous owners of Cadence Network, a company acquired by Ecova in 2008.

Other Businesses

The following table shows our assets related to our other businesses as of December 31 (dollars in thousands):



	2012		2011
Spokane Energy	$	54,235	$	66,317
Avista Energy	12,549		12,678
METALfx	11,273		11,919
Steam Plant and Courtyard Office Center	7,122		7,396
Other	10,459		13,835
Total	$	95,638	$	112,145

Spokane Energy is a special purpose limited liability company and all of its membership capital is owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. Of the total assets for Spokane Energy, the fixed rate electricity capacity contract represents $52.0 million and $62.5 million for 2012 and 2011, respectively and the likelihood of this asset being at risk of impairment is remote. In addition to the assets above, Spokane Energy also has nonrecourse long-term debt outstanding in the amount of $32.8 million and $46.5 million at December 31, 2012 and 2011, respectively, related to the acquisition of the fixed rate electric capacity contract. The final payment is due in January 2015 and Spokane Energy bears full recourse risk for the debt. See "Note 14 of the Notes to the Consolidated Financial Statements" for further discussion regarding this debt.

Avista Energy is a former electricity and natural gas marketing, trading and resource management business, which was a subsidiary of Avista Capital. This subsidiary has not been active since 2009; however, it continues to incur legal fees as it defends its actions related to several legal proceedings including the Federal Energy Regulatory Commission Inquiry, the

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California Refund Proceeding, the Pacific Northwest Refund Proceeding, and the California Attorney General Complaint (the “Lockyer Complaint”). See "Note 21 of the Notes to the Consolidated Financial Statements" for further detail regarding these legal proceedings. The assets associated with Avista Energy are deferred tax assets related to its former operations.

Advanced Manufacturing and Development (AM&D) doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries.

Steam Plant and Courtyard Office Center consist of real estate investments (primarily commercial office buildings).

Our other investments and operations include:


•	emerging technology venture capital funds, and


•	residual ownership of a fuel cell business that was previously a subsidiary of the Company.

Over time as opportunities arise, we dispose of investments and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that we believe fit with our overall corporate strategy.

We are focused on discovering new ways to accelerate growth for Avista Corp. within and adjacent to our core utility business and are planning to spend $2.0 million to $3.0 million in 2013 exploring opportunities to develop new markets and ways for customers to use electricity and natural gas for commercial productivity and transportation. We may also make other targeted investments that will help us gain strategic insights to build new growth platforms.

Item 1A. Risk Factors

Risk Factors

The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. Please also see “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Weather (temperatures, precipitation levels and storms) has a significant effect on our results of operations, financial condition and cash flows.

Weather impacts are described in the following subtopics:


•	retail electricity and natural gas sales,


•	the cost of natural gas supply,


•	the cost of power supply, and


•	damages to facilities.

Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues.

The cost of natural gas supply tends to increase with higher demand during periods of cold weather. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we have generally been allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales.

The cost of power supply can be significantly impacted by weather. Precipitation (consisting of snowpack, its water content and melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales

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is reduced. Wholesale prices also vary to a greater extent each year based on wind patterns as wind generation facilities have grown significantly in the region.

The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms.

As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.

Damages to facilities may be caused by severe weather, such as snow, ice or wind storms. The cost to implement rapid repair to such facilities can be significant. Overhead electric lines are most susceptible to such severe weather. Collateral damage from utility assets that are damaged by external forces may result in third party claims against the Company for property damage and/or personal injuries.

Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.

We have experienced higher costs for utility operations in each of the last several years. We have also made significant capital investments into utility plant assets. Our ability to recover these costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators grant substantially lower rate increases than our requests in the future or if deferred costs are disallowed, it could have a negative effect on our operating revenues, net income and cash flows. In addition, provisions to our approved settlement in the Washington general rate cases in 2012 and our proposed settlement to the Idaho general rate cases in 2013, do not prevent us from filing general rate cases in these two jurisdictions in 2014; however, new rates from these general rate case filings would not take effect prior to January 1, 2015.

Energy commodity price changes affect our cash flows and results of operations.

Energy commodity prices can be quite volatile. A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. These factors include:


•	Our obligation to serve our retail customers at rates set through the regulatory process. We cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval.


•	Customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors.


•	Some of our energy supply cost is fixed by nature of the energy-producing assets or through contractual arrangements. However, a significant portion of our energy resource costs are not fixed.

Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.

When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.

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Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer most of this difference for review by the regulatory commissions who have discretion as to the extent and timing of future recovery or refund to customers.

Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.

We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher or lower than what is currently authorized in retail rates by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators.

Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.

Our energy resource risk management processes can cause volatility in our cash flows and results of operations.

We engage in active hedging and resource optimization practices but we cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To reduce energy cost volatility and economic exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We do not cover the entire market price volatility exposure for our forecasted net positions. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows.

The hedges we enter into are reviewed for prudence by the various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.

We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them.

Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.

We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.

We rely on credit from financial institutions for short-term borrowings.

We need adequate levels of credit with financial institutions for short-term liquidity. We have a $400.0 million committed line of credit that is scheduled to expire in February 2017. There is no assurance that we will have access to credit beyond the expiration date. The committed line of credit agreement contains customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.

In July 2012, Ecova entered into a $125.0 million committed line of credit agreement with various financial institutions that replaced its $60.0 million committed line of credit agreement and has an expiration date of July 2017. There is no assurance

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that we will have access to credit beyond the expiration date. The committed line of credit agreement contains customary covenants and default provisions, and based on certain covenant conditions contained in the credit agreement, at December 31, 2012, Ecova could borrow an additional $5.6 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. See further discussion of the specific covenants in "Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations - Ecova Credit Agreement." In the event of default, it would be difficult for Ecova to obtain financing on reasonable terms to pay creditors or fund operations.

Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources.

If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us.

We are subject to various operational and event risks that are associated with the utility industry.

Our utility operations are subject to operational and event risks that include:


•	blackouts or disruptions to distribution, transmission or transportation systems,


•	forced outages at generating plants,


•	fuel cost and availability, including delivery constraints,


•	explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems, and


•	natural disasters that can disrupt energy generation, transmission and distribution.

As protection against operational and event risks, we maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us.

Ecova, may be unable to attain the level or timeliness of growth we expect.

Ecova's operations involve several recent acquisitions and may include other acquisitions as opportunities warrant. There are various uncertainties involved with assimilating acquired operations, achieving revenue growth and operating synergies in acquired operations. Ecova's organic growth and its ability to manage costs with the dynamics of growth and emerging business processes make it more difficult to accurately forecast cash flows and results of operations. As a result, earnings may be more volatile and cash flows may be irregular in this business segment.

Cyber attacks, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.

In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors. In particular, cyber attacks, terrorism or other malicious acts could damage, destroy or disrupt these systems. Any failure of technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer information or other proprietary data that could adversely affect our reputation and result in costly litigation. As these potential cyber attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems and respond to emerging concerns.

We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets.

Through our utility operations and the prior operations of Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints related to energy markets in the western United States. Most of these proceedings and complaints

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relate to the significant increase in the spot market price of energy in 2000 and 2001. This allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:


•	refund proceedings in California and the Pacific Northwest,


•	market conduct investigations by the FERC, and


•	complaints filed by various parties related to alleged misconduct by parties in western power markets.

As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from us, which could result in a negative effect on our results of operations and cash flows. See “Note 21 of the Notes to Consolidated Financial Statements” for further information.

There have been numerous recent changes in legislation, related administrative rulemaking, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.

We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC may perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation.

Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows.

Actions or limitations to address concerns over long-term global climate changes may affect our operations and financial performance.

Legislative developments and advocacy at the state, national and international levels concerning climate change and other environmental issues may have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources.

We expect continuing activity in the future and we are evaluating the extent that potential changes to environmental laws and regulations may:


•	increase the operating costs of generating plants,


•	increase the lead time and capital costs for the construction of new generating plants,


•	require modification of our existing generating plants,


•	require existing generating plant operations to be curtailed or shut down,


•	reduce the amount of energy available from our generating plants,


•	restrict the types of generating plants that can be built or contracted with, and


•	require construction of specific types of generation plants at higher cost.

We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.

In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 21 of the Notes to Consolidated Financial Statements” for further details of these matters.

Item 1B. Unresolved Staff Comments

As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the Securities and Exchange Commission.

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Item 2. Properties

Avista Utilities

Substantially all of our utility properties are subject to the lien of our mortgage indenture.

Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

Generation Properties



	No. of Units	Nameplate Rating (MW) (1)	Present Capability (MW) (2)
Hydroelectric Generating Stations (River)
Washington:
Long Lake (Spokane)	4	70.0	88.0
Little Falls (Spokane)	4	32.0	35.6
Nine Mile (Spokane) (5)	4	26.4	22.4
Upper Falls (Spokane)	1	10.0	10.2
Monroe Street (Spokane)	1	14.8	15.0
Idaho:
Cabinet Gorge (Clark Fork) (3)	4	265.0	273.0
Post Falls (Spokane)	6	14.8	15.4
Montana:
Noxon Rapids (Clark Fork)	5	480.6	562.4
Total Hydroelectric		913.6	1,022.0
Thermal Generating Stations
Washington:
Kettle Falls GS	1	50.7	53.5
Kettle Falls CT	1	7.2	6.9
Northeast CT	2	61.8	64.8
Boulder Park	6	24.6	24.0
Idaho:
Rathdrum CT	2	166.5	166.5
Montana:
Colstrip Units 3 and 4 (4)	2	233.4	222.0
Oregon:
Coyote Springs 2	1	287.0	284.4
Total Thermal		831.2	822.1
Total Generation Properties		1,744.8	1,844.1


(1)	Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.


(2)	Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2012.


(3)	The present capability of Cabinet Gorge is limited by our water rights. This output level reflects the maximum capability within our water rights. When river flows exceed these water rights limits, we are permitted to increase flow through the plant resulting in up to 265 MW.


(4)	Jointly owned; data refers to our 15 percent interest.


(5)	There are currently four units at the Nine Mile plant; however, the present capability is limited due to a mechanical failure of Units 1 and 2. A project is underway to replace these units and restore capability. The nameplate rating of the two remaining units is 18 MW.

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Electric Distribution and Transmission Plant

We own and operate approximately 18,600 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,534 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices, and other equipment.

The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the Bonneville Power Administration (BPA), Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.

These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system.

Natural Gas Plant

We have natural gas distribution mains of approximately 3,400 miles in Washington, 1,970 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 40 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.

We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. Our share of the peak day deliverability and total working capacity is one-third of these. Natural gas storage enables us to place natural gas into storage when prices are lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Item 3. Legal Proceedings

See “Note 21 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is currently listed on the New York Stock Exchange under the ticker symbol “AVA”. As of January 31, 2013, there were 10,083 registered shareholders of our common stock.

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:


•	our results of operations, cash flows and financial condition,


•	the success of our business strategies, and


•	general economic and competitive conditions.

Our net income available for dividends is generally derived from our regulated utility operations.

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock (when outstanding) contained in our Restated Articles of Incorporation, as amended.

On February 8, 2013, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.305 per share on the Company’s common stock. This was an increase of $0.015 per share, or 5 percent from the previous quarterly dividend of $0.29 per share.

For additional information, see “Notes 1, 18, 19 and 20 of Notes to Consolidated Financial Statements.”

The following table presents quarterly high and low stock prices as reported on the consolidated reporting system, as well as dividend information:



	Three Months Ended
	March 31		June 30		September 30		December 31
2012
Dividends paid per common share	$	0.29	$	0.29	$	0.29	$	0.29
Trading price range per common share:
High	$	26.18	$	27.07	$	28.05	$	26.77
Low	$	24.48	$	24.95	$	25.07	$	22.78
2011
Dividends paid per common share	$	0.275	$	0.275	$	0.275	$	0.275
Trading price range per common share:
High	$	23.69	$	25.83	$	26.53	$	26.35
Low	$	21.78	$	22.81	$	21.13	$	23.14

For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

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Item 6. Selected Financial Data



(in thousands, except per share data and ratios)	Years Ended December 31,
	2012			2011			2010			2009			2008
Operating Revenues:
Avista Utilities	$	1,354,185		$	1,443,322		$	1,419,646		$	1,395,201		$	1,572,664
Ecova	155,664			137,848			102,035			77,275			59,085
Other	38,953			40,410			61,067			40,089			45,014
Intersegment eliminations	(1,800		)	(1,800		)	(24,008		)	—			—
Total	$	1,547,002		$	1,619,780		$	1,558,740		$	1,512,565		$	1,676,763
Income (Loss) from Operations (pre-tax):
Avista Utilities (3)	$	188,778		$	202,373		$	198,200		$	188,511		$	170,067
Ecova	2,972			20,917			15,865			11,603			11,297
Other (3)	(1,680		)	4,714			5,669			(7,103		)	(1,454		)
Total	$	190,070		$	228,004		$	219,734		$	193,011		$	179,910
Net income	$	78,800		$	103,539		$	94,948		$	88,648		$	74,757
Net income attributable to noncontrolling interests	$	(590	)	$	(3,315	)	$	(2,523	)	$	(1,577	)	$	(1,137	)
Net Income (Loss) Attributable to Avista Corporation shareholders:
Avista Utilities	$	81,704		$	90,902		$	86,681		$	86,744		$	70,032
Ecova	1,825			9,671			7,433			5,329			6,090
Other	(5,319		)	(349		)	(1,689		)	(5,002		)	(2,502		)
Total	$	78,210		$	100,224		$	92,425		$	87,071		$	73,620
Average common shares outstanding, basic	59,028			57,872			55,595			54,694			53,637
Average common shares outstanding, diluted	59,201			58,092			55,824			54,942			54,028
Common shares outstanding at year-end	59,813			58,423			57,120			54,837			54,488
Earnings per Common Share Attributable to Avista Corporation shareholders:
Diluted	$	1.32		$	1.72		$	1.65		$	1.58		$	1.36
Basic	$	1.32		$	1.73		$	1.66		$	1.59		$	1.37
Dividends paid per common share	$	1.16		$	1.10		$	1.00		$	0.81		$	0.69
Book value per common share at year-end	$	21.06		$	20.30		$	19.71		$	19.17		$	18.30
Total Assets at Year-End:
Avista Utilities	$	3,894,821		$	3,809,446		$	3,589,235		$	3,400,384		$	3,434,844
Ecova	322,720			292,940			221,086			143,060			125,911
Other	95,638			112,145			129,774			63,515			69,992
Total	$	4,313,179		$	4,214,531		$	3,940,095		$	3,606,959		$	3,630,747
Long-Term Debt (including current portion)	$	1,228,739		$	1,177,300		$	1,101,857		$	1,071,338		$	826,465
Nonrecourse Long-Term Debt of Spokane
Energy (including current portion) (1)	$	32,803		$	46,471		$	58,934		$	—		$	—
Long-Term Debt to Affiliated Trusts	$	51,547		$	51,547		$	51,547		$	51,547		$	113,403
Total Avista Corporation Stockholders’ Equity	$	1,259,477		$	1,185,701		$	1,125,784		$	1,051,287		$	996,883
Ratio of Earnings to Fixed Charges (2)	2.47			3.06			2.86			2.95			2.43


(1)	Spokane Energy was consolidated effective January 1, 2010. See "Note 3 of the Notes to Consolidated Financial Statements."


(2)	See Exhibit 12 for computations.


(3)	Includes an immaterial correction of an error related to the reclassification of certain operating expenses from other expense-net to other operating expenses. This correction did not have an impact on net income or earnings per share. See "Note 1 of the Notes to Consolidated Financial Statements" for further information regarding this reclassification.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Business Segments

We have two reportable business segments as follows:


•	Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

•

Ecova – an indirect subsidiary of Avista Corp. (79.0 percent owned as of December 31, 2012) provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.

We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, as well as certain other operations of Avista Capital. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx.

The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):



	2012			2011			2010
Avista Utilities	$	81,704		$	90,902		$	86,681
Ecova	1,825			9,671			7,433
Other	(5,319		)	(349		)	(1,689		)
Net income attributable to Avista Corporation shareholders	$	78,210		$	100,224		$	92,425

Executive Level Summary

Overall

Net income attributable to Avista Corporation shareholders was $78.2 million for 2012, a decrease from $100.2 million for 2011. This was due to a decrease in earnings at each of our businesses. Earnings at Avista Utilities decreased primarily due to reduced retail loads during the first and fourth quarters of the year (as a result of warmer weather) and due in part to lower usage at certain industrial customers, due to temporary operational challenges. In addition, there were increases in other operating expenses (including costs under a voluntary severance incentive program), and depreciation and amortization, partially offset by the implementation of general rate increases. Net income at Ecova decreased as revenue growth for the expense and data management services and energy management services at Ecova was not as high as expected and did not offset increased operating costs. In addition, Ecova's earnings were reduced by increased costs associated with completing and integrating the acquisitions of Prenova and LPB and an increase in depreciation and amortization. Net income at other subsidiaries decreased due losses on investments, inclusive of an impairment loss recognized during the third quarter, increased costs associated with strategic consulting and other corporate costs, and increased litigation costs related to the previous operations of Avista Energy. These losses were partially offset by positive earnings at METALfx. These results, including a quantification of their respective impacts, are discussed in detail below.

Avista Utilities

Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things:


•	weather conditions,


•	regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment,


•	the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and


•	the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand.

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Based on our forecasts for our utility operations for 2013 through 2016, we expect annual electric customer growth to average 0.7 percent to 1.3 percent per year and annual natural gas customer growth to average 0.7 percent to 1.8 percent within our service area. We anticipate retail electric load growth to average between 0.7 percent and 1.0 percent and natural gas load growth to average between 0.7 percent and 1.4 percent. We anticipate customer and load growth at the lower end of the range in 2013 and a modest recovery as the economy strengthens during the four-year period. While the number of electric and natural gas customers is growing, the average annual usage by each residential customer has not changed significantly. For further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory, see "Economic Conditions and Utility Load Growth".

In our utility operations, we regularly review the need for rate changes in each jurisdiction to improve the recovery of costs and capital investments in our generation, transmission and distribution systems. General rate increases went into effect in Idaho on October 1, 2011, in Washington on January 1, 2012, and in Oregon effective March 15, 2011, June 1, 2011 and June 1, 2012. On October 11, 2012 we filed electric and natural gas general rate increase requests in Idaho, which are currently the subject of a settlement that is before the IPUC for approval (see discussion below under "Idaho General Rate Cases"). In December 2012, the UTC approved a settlement agreement in our Washington general rate cases, which were originally filed on April 2, 2012, that provides for electric and natural gas rate increases effective January 1, 2013 and January 1, 2014.

We are making significant capital investments in generation, transmission and distribution systems to preserve and enhance service reliability for our customers and replace aging infrastructure. Utility capital expenditures were $271.2 million for 2012. We expect utility capital expenditures to be about $260 million for each of 2013 and 2014. These estimates of capital expenditures are subject to continuing review and adjustment (see discussion under “Avista Utilities Capital Expenditures”).

On October 22, 2012, we announced a voluntary severance incentive program to reduce our total utility workforce and achieve necessary long-term, sustainable, Company-wide savings, in addition to other cost saving measures.

Based on the response to the program by interested employees and the approvals by Company management the program resulted in the termination of 55, or approximately 6 percent, of the eligible 919 non-union employees, and the total severance costs under the program were $7.3 million (pre-tax). The long-term operating and maintenance cost savings under the program are expected to exceed the severance costs of the program and the expected payback period for the severance costs will be approximately 1.4 years.

All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash payment to each participant during January 2013.

An agreement with one of our largest electric customers, which consumes approximately 100 aMWs per year, is expiring on June 30, 2013. We are currently renegotiating a new agreement with this customer that is expected to become effective July 1, 2013. The new agreement will be subject to approval from the IPUC once it is finalized. We would expect to receive regulatory recovery of any changes in costs or revenues related to the agreement.

Ecova

On November 30, 2011, Ecova acquired Prenova, an Atlanta-based energy management company. The cash paid for the acquisition of Prenova of $35.7 million was funded primarily through borrowings under Ecova's committed credit agreement.

On January 31, 2012, Ecova acquired LPB, a Dallas-based energy management company. The cash paid for the acquisition of LPB of $50.6 million was funded by Ecova through $25.0 million of borrowings under its committed credit agreement, a $20.0 million equity infusion from existing shareholders (including Avista Capital and the other owners of Ecova), and available cash.

While these acquisitions have grown the overall cost structure for Ecova for 2012, they have also increased both operating revenues and Ecova's market share and will allow Ecova to offer its clients a broader range of services which should lead to potential future earnings growth as the acquisitions are integrated with Ecova's operations.

The acquisition of Cadence Network in July 2008 was funded by issuing additional Ecova common stock. Under the transaction agreement, the previous owners of Cadence Network had a right to have their shares of Ecova common stock redeemed by Ecova during July 2011 or July 2012 if their investment in Ecova was not liquidated through either an initial public offering or sale of the business to a third party. These redemption rights were not exercised and expired effective July 31, 2012 and were reclassified to permanent equity, which resulted in a decrease of $41.6 million in redeemable noncontrolling interests from December 31, 2011.

The value of the remaining redeemable noncontrolling interests in Ecova associated with redeemable stock options and other

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outstanding redeemable stock was $4.9 million at December 31, 2012, a decrease from $12.9 million at December 31, 2011. Options are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price). During 2012, the estimated fair value of Ecova common stock decreased such that it is closer to the exercise price of the options which reduced the overall value of the redeemable noncontrolling interests down to their current value.

Ecova plans to continue to grow organically and possibly through strategic acquisitions. Ecova's acquisitions after 2008 have been funded through internally generated cash, borrowings under Ecova's credit facility and, in the case of LPB, an equity infusion from existing shareholders. If Ecova's capital needs exceed its credit facility capacity or management determines a different capital structure is necessary, Ecova may require additional equity infusions from existing shareholders and/or new funding sources.

We may seek to monetize all or part of our investment in Ecova in the future. The value of a potential monetization depends on future market conditions, growth of the business and other factors. A strategic change to Ecova's ownership structure may provide access to public market capital and provide potential liquidity to Avista Corp. and the other owners of Ecova. There can be no assurance that such a transaction will be completed.

Liquidity and Capital Resources

We have a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017. As of December 31, 2012, there were $52.0 million of cash borrowings and $35.9 million in letters of credit outstanding leaving $312.1 million of available liquidity under this line of credit.

In July 2012, Ecova entered into a five-year $125.0 million committed line of credit agreement with various financial institutions that replaced its $60.0 million committed line of credit agreement. As of December 31, 2012, Ecova had $54.0 million of borrowings outstanding under its committed line of credit agreement. Based on certain covenant conditions contained in the credit agreement, at December 31, 2012, Ecova could borrow an additional $5.6 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. We expect Ecova's earnings to increase in the future, so we expect the excess borrowing capacity to increase as well. See further discussion of the specific covenants below under "Ecova Credit Agreement".

In November 2012, we issued $80.0 million of 4.23 percent First Mortgage Bonds due in 2047 as an obligation of Avista Corp. Net total proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under our $400.0 million committed line of credit and for general corporate purposes. There are $50.0 million in First Mortgage Bonds maturing in 2013 and we expect to issue up to $100 million of long-term debt during the second half of 2013.

In May 2012, we cash settled interest rate swap contracts (notional amount of $75.0 million) and paid a total of $18.5 million. The interest rate swap contracts were settled in connection with the pricing of $80.0 million of First Mortgage Bonds as described above. Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the life of the forecasted interest payments.

In August 2012, we entered into two sales agency agreements under which we may issue up to 2.7 million shares of our common stock from time to time. In 2012, we sold 0.9 million shares and received net proceeds of $23.4 million (net of issuance costs). As of December 31, 2012, we had 1.8 million shares available to be issued under these agreements.

In 2012 we received net proceeds of $29.1 million (net of issuance costs) by issuing common stock, including $23.4 million under our sales agency agreements. During 2013, we expect to issue up to $50 million of common stock in order to maintain our capital structure at an appropriate level for our business. After considering the issuances of long-term debt and common stock during 2013, we expect net cash flows from operating activities, together with cash available under our $400.0 million committed line of credit agreement, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

Avista Utilities – Regulatory Matters

General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:


•	provide for recovery of operating costs and capital investments, and


•	provide the opportunity to improve our earned returns as allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in

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major revenue and expense items. We filed general rate cases in Washington in May 2011 (which were settled with new rates effective January 1, 2012) and in Idaho in July 2011 (which were settled with new rates effective October 1, 2011). We filed general rate cases in Washington in April 2012 (which were settled with new rates effective January 1, 2013 and January 1, 2014) and Idaho in October 2012 (which are the subject of a settlement that is before the IPUC (see discussion below under "Idaho General Rate Cases")).

Washington General Rate Cases

In November 2010, the UTC approved an all-party settlement stipulation in our general rate case filed in March 2010. As agreed to in the settlement stipulation, electric rates for Washington customers increased by an average of 7.4 percent, which was designed to increase annual revenues by $29.5 million. Natural gas rates for Washington customers increased by an average of 2.9 percent, which was designed to increase annual revenues by $4.6 million. The new electric and natural gas rates became effective on December 1, 2010.

In December 2011, the UTC approved a settlement agreement in our electric and natural gas general rate cases filed in May 2011. As agreed to in the settlement agreement, base electric rates for our Washington customers increased by an average of 4.6 percent, which was designed to increase annual revenues by $20.0 million. Base natural gas rates for our Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $3.75 million. The new electric and natural gas rates became effective on January 1, 2012.

The settlement agreement provided for the deferral of certain generation plant maintenance costs. In order to address the variability in year-to-year maintenance costs, beginning in 2011, we deferred certain changes in maintenance costs related to our Coyote Springs 2 natural gas-fired generation plant and our 15 percent ownership interest in Units 3&4 of the Colstrip generation plant. These maintenance costs may be much higher in certain years because certain significant maintenance procedures are less frequent than annual and, therefore, may not be properly represented in test year expenses used in our filed rate requests. For 2011 and 2012 the Company compared actual, non-fuel, maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline maintenance expenses used to establish base retail rates, and deferred the difference. This deferral occurred annually, with no carrying charge, with deferred costs being amortized over a four-year period, beginning in the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases would be the actual maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this mechanism in Washington were a regulatory asset of $4.0 million as of December 31, 2012 compared to a regulatory liability of $0.5 million as of December 31, 2011. As part of the settlement agreement in October 2012 to our latest general rate case discussed in further detail below, the parties have agreed that the maintenance cost deferral mechanism on these generation plants will terminate on December 31, 2012, with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.

In December 2012, the UTC approved a settlement agreement in our electric and natural gas general rate cases filed in April 2012. As agreed to in the settlement, effective January 1, 2013, base rates for our Washington electric customers increased by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for our Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). The settling parties agree that a one-year credit of $4.4 million will be returned to electric customers from the existing Energy Recovery Mechanism (ERM) deferral balance so the net average electric rate increase to our customers in 2013 will be 2.0 percent. The credit to customers from the ERM balance will not impact our earnings.

The settlement also provided that, effective January 1, 2014, we will increase base rates for our Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for our Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settling parties agree that a one-year credit of $9.0 million will be returned to electric customers from the then-existing ERM deferral balance, if such funds are available, so the net average electric rate increase to our customers effective January 1, 2014 will be 2.0 percent. The credit to customers from the ERM balance will not impact our earnings.

The UTC Order approving the settlement agreement included certain conditions. The new retail rates to become effective January 1, 2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any intervening action from the UTC. Included in the original settlement agreement is a provision that we will not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. We can, however, make a filing prior to January 1, 2015, but new rates resulting from the filing would not take effect prior to January 1, 2015. We currently intend to file a general rate case in early 2014 with proposed rates that would take effect on January 1, 2015. This provision does not preclude us from filing annual rate adjustments such as the PCA and the PGA.

In addition, in its Order, the UTC found that much of the approved base rate increases is justified by the planned capital expenditures necessary to upgrade and maintain our utility facilities. If these capital projects are not completed to a level that was contemplated in the original settlement agreement, this could result in base rates which are considered too high by the

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UTC. As a result, we must file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. We expect total utility capital expenditures among all jurisdictions to be approximately $260 million for each of 2013 and 2014.

The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47 percent, resulting in an overall return on rate base of 7.64 percent.

Idaho General Rate Cases

In September 2010, the IPUC approved a settlement agreement with respect to our general rate case filed in March 2010. The new electric and natural gas rates became effective on October 1, 2010. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 9.3 percent, which was designed to increase annual revenues by $21.2 million. Base natural gas rates for our Idaho customers increased by an average of 2.6 percent, which was designed to increase annual revenues by $1.8 million.

The settlement agreement included a rate mitigation plan under which the impact on customers of the new rates was reduced by amortizing $11.1 million ($17.5 million when grossed up for income taxes and other revenue-related items) of previously deferred state income taxes over a two-year period as a credit to customers. While our cash collections from customers are reduced by this amortization during the two-year period, the mitigation plan has no impact on our net income. Retail rates increased on October 1, 2011 and October 1, 2012 as the previously deferred state income tax balance was amortized.

In September 2011, the IPUC approved a settlement agreement in our general rate case filed in July 2011. The new electric and natural gas rates became effective on October 1, 2011. As agreed to in the settlement agreement, base electric rates for our Idaho customers increased by an average of 1.1 percent, which is designed to increase annual revenues by $2.8 million. Base natural gas rates for our Idaho customers increased by an average of 1.6 percent, which is designed to increase annual revenues by $1.1 million.

As part of the settlement agreement, we agreed not to file a general rate case seeking changes in base electric or natural gas rates effective prior to April 1, 2013. This does not preclude us from filing annual rate adjustments such as the PCA and the PGA.

The settlement agreement also provides for the deferral of certain generation plant operation and maintenance costs. In order to address the variability in year-to-year operation and maintenance costs, beginning in 2011, we are deferring certain changes in operation and maintenance costs related to the Coyote Springs 2 natural gas-fired generation plant and our 15 percent ownership interest in Units 3&4 of the Colstrip generation plant. We compare actual, non-fuel, operation and maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defer the difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this mechanism in Idaho were regulatory assets of $2.3 million as of December 31, 2012 and $0.1 million as of December 31, 2011.

On October 11, 2012, we filed electric and natural gas general rate cases with the IPUC. We requested an overall increase in electric rates of 4.6 percent and an overall increase in natural gas rates of 7.2 percent. The filings were designed to increase annual electric revenues by $11.4 million and increase annual natural gas revenues by $4.6 million. Our requests were based on a proposed overall rate of return of 8.46 percent, with a common equity ratio of 50 percent and a 10.9 percent return on equity.

On February 6, 2013, Avista Corp. and certain other parties filed a settlement agreement with the IPUC with respect to our electric and natural gas general rate cases. Parties to the settlement agreement include the staff of the IPUC, Clearwater Paper Corporation, Idaho Forest Group, LLC, the Idaho Conservation League, and the Company. Community Action Partnership Association of Idaho (CAPAI), a low-income customer advocacy group, and the Snake River Alliance did not join in the settlement agreement. However, on February 20, 2013 the Snake River Alliance provided a letter to the IPUC supporting the settlement agreement. This settlement agreement is subject to approval by the IPUC and would conclude the proceedings related the general rate requests filed by the Company on October 11, 2012. New rates would be implemented in two phases: April 1, 2013 and October 1, 2013.

The settlement agreement proposes that, effective April 1, 2013, we would be authorized to implement a base rate increase for our Idaho natural gas customers of 4.9 percent (designed to increase annual revenues by $3.1 million). There would be no change in base electric rates on April 1, 2013. However, the settlement agreement would provide for the recovery of the costs of the Palouse Wind Project through the Power Cost Adjustment mechanism beginning April 1, 2013.