10-K 1 ava-20151231x10k.htm 10-K 10-K

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, 2015 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.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an 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 $1,909,309,138 based on the last reported sale price thereof on the consolidated tape on June 30, 2015.
As of January 31, 2016, 62,494,881 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 12, 2016.
Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 7, 2015.
 
Part III, Items 10, 11,
12, 13 and 14



AVISTA CORPORATION



INDEX 
Item
No.
 
 
Page
No.
 
 
 
 
 
 
 
 
 
 
 
 
Part I
 
 
1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1A.
 
 
1B.
 
 
2
 
 
 
 
 
3
 
 
4
 
*
 
 
Part II
 
 
5
 
 
6
 
 
7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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AVISTA CORPORATION



 
 
 
 
 
 
7A.
 
 
8.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9.
 
*
9A.
 
 
9B.
 
 
 
 
Part III
 
 
10.
 
 
11.
 
 
12.
 
 
13.
 
 
14.
 
 
 
 
Part IV
 
 
15.
 
 
 
 
 
 
 
 
 * = not an applicable item in the 2015 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
AEL&P
-
Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska
AERC
-
Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska
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
ASU
-
Accounting Standards Update
Avista Capital
-
Parent company to the Company’s non-utility businesses
Avista Corp.
-
Avista Corporation, the Company
Avista Energy
-
Avista Energy, Inc., an inactive electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital
Avista Utilities
-
Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest
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 combined-cycle 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 ERM 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. Ecova was sold on June 30, 2014.
EIM
-
Energy Imbalance Market
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
GS
-
Generating station
IPUC
-
Idaho Public Utilities Commission
IRP
-
Integrated Resource Plan

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Jackson Prairie
-
Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington
Juneau
-
The City and Borough of Juneau, Alaska
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
MPSC
-
Public Service Commission of the State of Montana
MW, MWh
-
Megawatt: 1000 KW. Megawatt-hour: 1000 KWh
NERC
-
North American Electricity Reliability Corporation
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
RCA
-
The Regulatory Commission of Alaska
REC
-
Renewable energy credit
RTO
-
Regional Transmission Organization
Salix
-
Salix, Inc., a subsidiary of Avista Capital, launched in 2014 to explore markets that could be served with liquefied natural gas (LNG), primarily in western North America.
Spokane Energy
-
Spokane Energy, LLC (dissolved in the third quarter of 2015), a special purpose limited liability company and all of its membership capital was owned by Avista Corp.
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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AVISTA CORPORATION



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 are based upon 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. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:
Financial Risk
weather conditions (temperatures, precipitation levels and wind patterns) which affect both energy demand and electric generating capability, 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 effects on supply and demand in the wholesale energy markets;
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;
changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent we recover interest costs through utility operations;
changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
external pressure to meet financial goals that can lead to short-term or expedient decisions that reduce the likelihood of long-term objectives being met;
deterioration in the creditworthiness of our customers;
the outcome of pending legal proceedings arising out of the “western energy crisis” of 2000 and 2001, specifically related to the Pacific Northwest refund proceedings;
the outcome of legal proceedings and other contingencies;
economic conditions in our service areas, including the economy's effects on customer demand for utility services;
declining energy demand related to customer energy efficiency and/or conservation measures;
changes in the long-term global and our utilities' service area climates, 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;

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AVISTA CORPORATION



Utility Regulatory Risk
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, operating costs and commodity costs and discretion over allowed return on investment;
possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions;
Energy Commodity Risk
volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, 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 in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;
default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;
potential obsolescence of our power supply resources;
Operational Risk
severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, 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 impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations and may require us to purchase replacement power;
public injuries or damage arising from or allegedly arising from our operations;
blackouts or disruptions of interconnected transmission systems (the regional power grid);
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;
work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;
increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
third party construction of buildings, billboard signs or towers within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;
the loss of key suppliers for materials or services or disruptions to the supply chain;
increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees;
adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel);
Compliance Risk
compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs;
the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels;

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AVISTA CORPORATION



Technology Risk
cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation;
disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;
changes in the costs to operate and maintain current production technology or to implement new information technology systems that impede our ability to complete such projects timely and effectively;
changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security related risk;
insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;
Strategic Risk
growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites;
potential difficulties 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;
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 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 and the extent of our business development efforts where potential future business is uncertain;
External Mandates Risk
changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;
the potential effects of legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;
political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;
wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;
failure by us to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business; and
the risk of municipalization in any of our service territories.
Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonably 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 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.

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AVISTA CORPORATION



Available Information
Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available on our Web site as soon as practicable after electronically filing these reports with the U.S. Securities and Exchange Commission (SEC). Information contained on our Web site is not part of this report. 
PART I
ITEM 1. BUSINESS
COMPANY OVERVIEW
Avista Corporation, incorporated in the territory of Washington in 1889, is primarily an electric and natural gas utility with certain other business ventures. As of December 31, 2015, we employed 1,711 people in our Pacific Northwest utility operations (Avista Utilities) and 227 people in our subsidiary businesses (including our Juneau, Alaska utility operations). 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. Through our subsidiary AEL&P, we also provide electric utility services in the City and Borough of Juneau (Juneau), Alaska.
As of December 31, 2015, we have two reportable business segments as follows:
Avista Utilities – an operating division of Avista Corp. (not a subsidiary) that comprises our regulated utility operations in the Pacific Northwest. Avista Utilities generates, transmits and distributes electricity and distributes natural gas, serving electric and natural gas customers in eastern Washington and northern Idaho and natural gas customers in parts of Oregon. We also supply electricity to a small number of customers in Montana, most of whom are our employees who operate our Noxon Rapids generating facility. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.
AEL&P - a utility providing electric services in Juneau, Alaska and the primary operating subsidiary of AERC. We acquired AERC on July 1, 2014, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. See "Note 4 of the Notes to Consolidated Financial Statements" for further discussion regarding this acquisition.
We have other businesses, including sheet metal fabrication, venture fund investments, real estate investments, a company that explores markets that could be served with LNG, as well as certain other investments of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. 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.
Total Avista Corp. shareholders’ equity was $1,528.6 million as of December 31, 2015, of which $57.4 million represented our investment in Avista Capital and $95.4 million represented our investment in AERC.
See “Item 6. Selected Financial Data” and “Note 21 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).
AVISTA UTILITIES
General
At the end of 2015, we supplied retail electric service to 375,000 customers and retail natural gas service to 335,000 customers across Avista Utilities' service territory. Avista Utilities' service territory covers 30,000 square miles with a population of 1.6 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
General Avista Utilities generates, transmits and distributes electricity, serving electric customers in eastern Washington, northern Idaho and a small number of customers in Montana.
Avista Utilities generates electricity from facilities that we own and purchases capacity, energy and fuel for generation under long-term and short-term contracts to meet customer load obligations. 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.

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AVISTA CORPORATION



As part of Avista Utilities' 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 then capture additional economic value through market transactions. We engage in transactions 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 available resources with 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 scheduling and dispatching available resources as well as the following:
purchasing fuel for generation,
when economical, selling fuel and substituting wholesale electric purchases, and
other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts.
This optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments.
Avista Utilities' generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. Avista acquires both long term and short term transmission capacity to facilitate all of our energy and capacity transactions. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana.
Electric Requirements
Avista Utilities' peak electric native load requirement for 2015 occurred on August 12, 2015, at which time our peak electric native load was 1,638 MW. In 2014 and 2013, our peak electric native load requirements were 1,715 and 1,669 MW, respectively, both of which occurred during the winter.
Electric Resources
Avista Utilities has 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 2015, our Company-owned facilities had a total net capability of 1,841 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities.
Hydroelectric Resources Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is typically our lowest cost source per 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 2016 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 533 aMW (or 4.6 million MWhs).

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AVISTA CORPORATION



The following graph shows Avista Utilities' hydroelectric generation (in thousands of MWhs) during the year ended December 31:
(1)
Normal hydroelectric generation is determined by applying an upstream regulation calculation to median natural water flow information. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flow changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year.
Thermal Resources Avista Utilities owns the following thermal resources:
the combined cycle CT natural gas-fired Coyote Springs 2 located near Boardman, Oregon,
a 15 percent interest in a twin-unit, coal-fired boiler generating facility, Colstrip 3 & 4, located in southeastern Montana,
a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington,
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 Talen Energy 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.

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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.
Lancaster Plant We have the exclusive rights to capacity of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in northern 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). Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive all of the electric energy output from the Lancaster Plant; therefore, we consider this plant in our baseload resources. See "Note 3 of the Notes to Consolidated Financial Statements" for further discussion of this PPA.
 
The following graph shows Avista Utilities' thermal generation (in thousands of MWhs) during the year ended December 31:
Wind Resources Palouse Wind is a wind generation project developed by Palouse Wind, LLC, and located in Whitman County, Washington. We have a 30-year PPA (expires in 2042) to acquire all of the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of approximately 105 MW. Generation from Palouse Wind was 293,563 MWhs in 2015, 335,291 MWhs in 2014 and 297,027 MWhs in 2013. We have an annual option to purchase the wind project following the 10th anniversary of its December 2012 commercial operation date. The purchase price per the PPA is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining 20 year term of the agreement.
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 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 UTC and the IPUC.
See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2015, 2014 and 2013. 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 Licenses
Avista Corp. is a licensee under the Federal Power Act (FPA) 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 FPA. 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.
Cabinet Gorge and Noxon Rapids are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 19 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal numeric water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway as well as of 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.
Future Resource Needs
Avista Utilities has 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 1,047 aMW in 2015, 1,062 aMW in 2014 and 1,086 aMW in 2013.
The following is a forecast of our average annual energy requirements and resources for 2016 through 2019:

(1)
The contracts for power sales decrease due to certain contracts expiring in each of these years. We are evaluating the future plan for the additional resources made available due to the expiration of these contracts.
(2)
The forecast assumes near normal hydroelectric generation.
(3)
Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements.
(4)
The combined maximum capacity of Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT is 278 MW, with estimated available energy production as indicated for each year.

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In August 2015, we filed our 2015 Electric IRP with the UTC and the IPUC. The UTC and IPUC review the IRPs and give the public the opportunity to comment. The UTC and IPUC do not approve or disapprove of the content in the IRPs; rather they only acknowledge that the IRPs were prepared in accordance with applicable standards if that is the case. 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 2015 IRP include:
We have adequate resources between our owned and contractually controlled generation, combined with conservation and market purchases, to meet customer needs through 2020.
565 MW of additional generation capacity is required for the period 2020 through 2034.
We expect to meet or exceed the renewable energy requirements of the Washington state Energy Independence Act through the 20-year IRP time frame with a combination of qualifying hydroelectric upgrades, the 30-year PPA with Palouse Wind, the Kettle Falls GS and selective REC purchases.
Load growth is expected to be approximately 0.6 percent, a decline from the growth of 1.0 percent forecasted in 2013. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years and the load impacts of increased prices. See "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory. The estimates of future load growth in the IRP and at "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" differ slightly due to the timing of when the two estimates were prepared and due to the time period that each estimate is focused on.
Colstrip remains a cost effective and reliable source of power to meet future customer needs.
Energy efficiency offsets more than half of projected load growth through the 20-year IRP time frame.
Demand response (temporarily reducing the demand for energy) was eliminated from the Preferred Resource Strategy due to higher estimated costs.
We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2017. Our resource strategy may change from the 2015 IRP based on market, legislative and regulatory developments.
We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective conservation measures. Future generation resource decisions will be impacted by legislation for restrictions on GHG emissions and renewable energy requirements.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix.
Natural Gas Operations
General Avista Utilities provides 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. Our natural gas procurement strategy is to provide reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of spot market purchases and forward fixed price purchases, utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.
Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted 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 portion

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of our customers' 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 portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets.
Our purchase of natural gas supply is governed by our procurement plan, which is reviewed and approved annually by the Risk Management Committee (RMC), which is comprised of certain officers and other management personnel. Once approval is received, the plan is implemented and monitored by our gas supply and risk management groups.
The plan’s progress is also presented to the UTC and IPUC staff in semi-annual meetings, and updates are given to the OPUC staff quarterly. Other stakeholders (Public Counsel Unit of the Office of the Attorney General, Citizen Utility Board) are invited to participate. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Any material changes to the plan are documented and communicated to RMC members.
As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. As such, we generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to:
wholesale market sales of surplus natural gas supplies,
purchases and sales of natural gas to optimize use of pipeline and storage capacity, and
participation in the transportation capacity release market.
We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and redeliver it to the customers’ premise.
Optimization transactions that we engage in throughout the year are included in our annual purchased gas cost adjustment filings with the various commissions and they are subject to review for prudency during this process.
Natural Gas Supply Avista Utilities purchases all of its natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different 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 transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian sourced supply. 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 resource mix to vary.
Natural Gas Storage Avista Utilities owns a one-third interest in Jackson Prairie, an underground aquifer natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 12 million therms, with a total working natural gas capacity of 256 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project.
We optimize our natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdraw during higher priced months, typically during the winter. However, if market conditions and prices indicate that we should buy or sell natural gas during other times in the year, we engage in optimization transactions to capture value in the marketplace. Jackson Prairie is also used as a variable peaking resource and to protect from extreme daily price volatility during cold weather or other events affecting the market.
Future Resource Needs In August 2014, we filed our 2014 Natural Gas IRP with the UTC, IPUC and the OPUC. The natural gas IRPs are similar in nature to the electric IRPs and the process for preparation and review by the state commissions of both the electric and natural gas IRPs is similar. 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.

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Highlights of the 2014 IRP include:
We have sufficient natural gas transportation resources well into the future with resource needs not occurring during the 20 year planning horizon in Washington, Idaho, or Oregon.
Natural gas commodity prices continue to be relatively stable due to robust North American supplies led by shale gas development; and
As forecasted demand is relatively flat, we will monitor actual demand for signs of increased growth which could accelerate resource needs.
We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2016. Our resource strategy may change from the 2014 IRP based on market, legislative and regulatory developments.
Regulatory Issues
General As a public utility, Avista Corp. is 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 OPUC and the MPSC. Approval of the issuance of securities is not required from the MPSC. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.
Since Avista Corp. is a “holding company,” we are also subject to the jurisdiction of the FERC under the Public Utility Holding Company Act of 2005, which imposes certain reporting and other requirements. We, and all of our subsidiaries (whether or not engaged in any energy related business), are required to maintain books, accounts and other records in accordance with the FERC regulations and to make them available to the FERC and the state utility commissions. In addition, upon the request of any state utility commission, or of Avista Corp., the FERC would have the authority to review assignment of costs of non-power goods and administrative services among us and our subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions of any affiliated company.
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 generally determined on a “cost of service” basis. 
 
Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a return of and 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 income 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, requests for new retail rates are made on the basis of net investment, operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including but not limited to, unexpected changes in revenues, expenses and investment following the time new retail rates are requested in the rate proceeding, and exclusion of certain costs and investment by the commission from the rate making process.
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 20 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes.
General Rate Cases Avista Utilities regularly reviews 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 – Regulatory Matters – General Rate Cases” for information on general rate case activity.
Power Cost Deferrals Avista Utilities defers 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 – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 20 of the Notes to Consolidated Financial Statements” for information on power cost deferrals and recovery mechanisms in Washington and Idaho.

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Purchased Gas Adjustment (PGA) Under established regulatory practices in each state, Avista Utilities defers the recognition in the income statement of the natural gas costs that vary from the level currently recovered from our retail customers as authorized by each of our jurisdictions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – Purchased Gas Adjustments” and “Note 20 of the Notes to Consolidated Financial Statements” for 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 FPA 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 Order No. 888 and continuing with subsequent rulemakings and policies, 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) or an independent system operator (ISO).
Regional Transmission Planning
Avista Utilities meets its FERC requirements to coordinate transmission planning activities with other regional entities through ColumbiaGrid. ColumbiaGrid is a Washington nonprofit membership corporation with an independent board formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. We became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs those functions that its members request, as set forth in specific agreements. Currently, ColumbiaGrid fills the role of facilitating our regional transmission planning as required in FERC Order No. 1000 and other clarifying FERC Orders. ColumbiaGrid and its members also work with other western organizations to address transmission planning, including WestConnect and the Northern Tier Transmission Group (NTTG). In 2011, we became a registered Planning Participant of the NTTG. 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.
Regional Energy Markets
The California Independent System Operator (CAISO) recently implemented an EIM in the western United States. Several Pacific Norhwest utilities are either participants in the CAISO EIM or plan to integrate into the market in the next few years, which could reduce bilateral market liquidity and transaction opportunities in the Pacific Northwest. Avista Utilities is monitoring the CAISO EIM implementation but currently does not plan to join as a participating member. We will continue to monitor the CAISO EIM expansion and the associated impacts. As market fundamentals and our business needs evolve, we will weigh the advantages and disadvantages of joining the CAISO EIM or other organized energy markets in the future.
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 penalties for non-compliance with these standards and other FERC regulations.
The FERC certified the 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

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FERC approved the 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. Requirements relating to cyber security are continually evolving. Our compliance with version 5 of the NERC's Critical Infrastructure Protection standard is driving several physical and electronic security initiatives in our control centers, generating stations and substations. We do not expect the costs of the physical and electronic securities initiatives to have a material impact to our financial results.

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
ELECTRIC OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
335,552

 
$
338,697

 
$
331,867

Commercial
308,210

 
300,109

 
289,604

Industrial
111,770

 
110,775

 
113,632

Public street and highway lighting
7,277

 
7,549

 
7,267

Total retail
762,809

 
757,130

 
742,370

Wholesale
127,253

 
138,162

 
127,556

Sales of fuel
82,853

 
83,732

 
126,657

Other
25,839

 
27,467

 
36,071

Decoupling
4,740

 

 

Provision for earnings sharing
(5,621
)
 
(7,503
)
 
(2,048
)
Total electric operating revenues
$
997,873

 
$
998,988

 
$
1,030,606

ENERGY SALES (Thousands of MWhs):
 
 
 
 
 
Residential
3,571

 
3,694

 
3,745

Commercial
3,197

 
3,189

 
3,147

Industrial
1,812

 
1,868

 
1,979

Public street and highway lighting
23

 
25

 
26

Total retail
8,603

 
8,776

 
8,897

Wholesale
3,145

 
3,686

 
3,874

Total electric energy sales
11,748

 
12,462

 
12,771

ENERGY RESOURCES (Thousands of MWhs):
 
 
 
 
 
Hydro generation (from Company facilities)
3,434

 
4,143

 
3,646

Thermal generation (from Company facilities)
3,983

 
3,252

 
3,383

Purchased power
4,899

 
5,615

 
6,375

Power exchanges
(2
)
 
(25
)
 
(20
)
Total power resources
12,314

 
12,985

 
13,384

Energy losses and Company use
(566
)
 
(523
)
 
(613
)
Total energy resources (net of losses)
11,748

 
12,462

 
12,771

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
327,057

 
324,188

 
321,098

Commercial
41,296

 
40,988

 
40,202

Industrial
1,353

 
1,385

 
1,386

Public street and highway lighting
529

 
531

 
527

Total electric retail customers
370,235

 
367,092

 
363,213

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (KWh)
10,827

 
11,394

 
11,664

Revenue per KWh (in cents)
9.40

 
9.17

 
8.86

Annual revenue per customer
$
1,017.21

 
$
1,044.76

 
$
1,033.54

AVERAGE HOURLY LOAD (aMW)
1,047

 
1,062

 
1,086



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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
Years Ended December 31,
 
2015
 
2014
 
2013
RETAIL NATIVE LOAD at time of system peak (MW):
 
 
 
 
 
Winter
1,529

 
1,715

 
1,669

Summer
1,638

 
1,606

 
1,577

COOLING DEGREE DAYS: (1)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
805

 
631

 
709

Historical average
334

 
394

 
394

% of average
241
%
 
160
%
 
180
%
HEATING DEGREE DAYS: (2)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
5,614

 
6,215

 
6,683

Historical average
6,491

 
6,820

 
6,780

% of average
86
%
 
91
%
 
99
%

(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). In 2015, we switched to a rolling 20-year average for calculating cooling degree days, whereas in prior years we used a 30-year rolling average.
(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). In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average.

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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
NATURAL GAS OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
193,825

 
$
203,373

 
$
206,330

Commercial
96,751

 
103,179

 
102,225

Interruptible
2,782

 
2,792

 
2,681

Industrial
3,792

 
4,158

 
3,599

Total retail
297,150

 
313,502

 
314,835

Wholesale
204,289

 
228,187

 
194,717

Transportation
7,988

 
7,735

 
7,576

Other
5,578

 
7,461

 
8,573

Decoupling
6,004

 

 

Provision for earnings sharing

 
(221
)
 
(442
)
Total natural gas operating revenues
$
521,009

 
$
556,664

 
$
525,259

THERMS DELIVERED (Thousands of Therms):
 
 
 
 
 
Residential
176,613

 
190,171

 
204,711

Commercial
107,894

 
116,748

 
122,245

Interruptible
4,708

 
5,033

 
5,694

Industrial
5,070

 
5,648

 
5,181

Total retail
294,285

 
317,600

 
337,831

Wholesale
809,132

 
545,620

 
524,818

Transportation
164,679

 
162,311

 
159,976

Interdepartmental and Company use
335

 
411

 
418

Total therms delivered
1,268,431

 
1,025,942

 
1,023,043

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
296,005

 
291,928

 
288,708

Commercial
34,229

 
34,047

 
33,932

Interruptible
35

 
37

 
38

Industrial
261

 
264

 
259

Total natural gas retail customers
330,530

 
326,276

 
322,937

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (therms)
593

 
651

 
709

Revenue per therm (in dollars)
$
1.10

 
$
1.07

 
$
1.01

Annual revenue per customer
$
650.83

 
$
696.66

 
$
714.67

HEATING DEGREE DAYS: (1)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
5,614

 
6,215

 
6,683

Historical average (2)
6,491

 
6,820

 
6,780

% of average
86
%
 
91
%
 
99
%
Medford, OR
 
 
 
 
 
Actual
3,534

 
3,382

 
4,576

Historical average (2)
4,150

 
4,539

 
4,539

% of average
85
%
 
75
%
 
101
%
(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).
(2)
In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average.

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ALASKA ELECTRIC LIGHT AND POWER COMPANY
AEL&P is the primary operating subsidiary of AERC. AEL&P is the sole utility providing electrical energy in Juneau, Alaska. Juneau is a geographically isolated community with no electric interconnections with the transmission facilities of other utilities and no pipeline access to natural gas or other fuels. Juneau’s economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska.

AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity as of December 31, 2015. AEL&P owns four of these generation facilities (totaling 24.7 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78 MW of capacity).

The Snettisham hydroelectric project is owned by the Alaska Industrial Development and Export Authority (AIDEA), a public corporation of the State of Alaska. AEL&P has a PPA and operating and maintenance agreement with the AIDEA to operate and maintain the facility. This PPA is a take-or-pay obligation expiring in December 2038, to purchase all of the output of the project.

For accounting purposes, this PPA is treated as a capital lease and as of December 31, 2015, the capital lease obligation was $64.5 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for the principal amount of the bonds outstanding at that time. See "Note 14 of the Notes to Consolidated Financial Statements" for further discussion of the Snettisham capital lease obligation.

As of December 31, 2015, AEL&P also had 93.9 MW of diesel generating capacity from three facilities to provide back-up service to firm customers when necessary.
The following graph shows AEL&P's hydroelectric generation (in thousands of MWhs) during the time periods indicated below:
Only the hydroelectric generation for the second half of 2014 in the graph above was included in Avista Corp.'s overall results for 2014. The full 12 months of 2014 in the graph above is presented for information purposes only.

As of December 31, 2015, AEL&P served approximately 17,000 customers. Its primary customers include city, state and federal governmental entities located in Juneau, as well as a mine located in the Juneau area. Most of AEL&P’s customers are served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates.


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AEL&P’s operations are subject to regulation by the RCA with respect to rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities. Rate adjustments for AEL&P’s customers require approval by the RCA pursuant to RCA regulations. AEL&P's last general rate case was filed in 2010 and approved by the RCA in 2011. The RCA approved a capital structure including 53.8 percent equity and an authorized return on equity of 12.875 percent. We expect that AEL&P will maintain a similar capital structure going forward.
 
AEL&P is also subject to the jurisdiction of the FERC concerning the permits and licenses necessary to operate certain of its hydroelectric facilities. One of these licenses (for the Salmon Creek and Annex Creek hydroelectric projects) expires in 2018. Since AEL&P has no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction.

The Snettisham hydroelectric project is subject to regulation by the State of Alaska with respect to dam safety and certain aspects of its operations. In addition, AEL&P is subject to regulation with respect to air and water quality, land use and other environmental matters under both federal and state laws.
OTHER BUSINESSES
The following graph shows our assets related to our other businesses as of December 31 (dollars in thousands):
Spokane Energy was a special purpose limited liability company and all of its membership capital was 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. The fixed rate electric capacity contract, which expires in December 2016, was transferred from Spokane Energy to Avista Corp. during the second quarter of 2015. Spokane Energy was then dissolved during the third quarter of 2015. The fixed rate electric capacity contract has a value of $14.7 million as of December 31, 2015, compared to $28.2 million as of December 31, 2014.
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 mixed use commercial and retail office space).
AJT Mining is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain properties.
The assets at Avista Capital - standalone as of December 31, 2014 primarily consisted of the escrow receivables related to the sale of Ecova on June 30, 2014. The escrow receivables were settled and we received the proceeds during the fourth quarter of 2015. See "Note 5 of the Notes to Consolidated Financial Statements" for further detail regarding this transaction.

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Our other investments and operations include emerging technology venture capital funds.
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 continue to evaluate the opportunity to bring natural gas to Juneau, Alaska. If we pursue this project, we estimate that the total investment for our local distribution company (LDC) project would be about $130 million over 10 years, with about half being invested during the first five years.
Lower oil prices have made it more difficult for customers to justify converting to natural gas. In addition, we have yet to secure a mechanism to provide funds that are needed to help customers with the conversion costs, thus challenging the economics of the project. In addition, the state of Alaska has not yet adopted legislation that would enable the state to provide customer assistance for conversions. We will continue our due diligence and we will be ready to proceed if and when the economics prove favorable for customers and our Company.
Salix was notified by AIDEA in December 2015 that its proposal to build an LNG liquefaction plant to serve the Interior Energy Project, specifically to serve the Fairbanks, Alaska area, was selected as one of the two finalists. A decision by the AIDEA board is expected in early 2016.
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 future results or outcomes to differ materially from those discussed in our reports filed with the SEC (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.
Financial Risk Factors
Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows.
Weather impacts are described in the following subtopics:
certain retail electricity and natural gas sales,
the cost of natural gas supply, and
the cost of power supply.
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 the Pacific Northwest. 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 are generally 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. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in our region, even though there may be less extreme weather conditions in our area.
The cost of power supply can be significantly affected 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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AVISTA CORPORATION



is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in our region but its contribution to supply is inconsistent.
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.
The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.
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.
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 expires in April 2019. Our subsidiary AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. There is no assurance that we will have access to credit beyond these expiration dates. The committed line of credit agreements contain 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.
We hedge a portion of our interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. If market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap agreements, which can be significant. As of December 31, 2015, we had a net interest rate derivative liability of $84.0 million, reflecting a decline in interest rates since the time we entered the agreements. We did not have any U.S. Treasury lock agreements outstanding as of December 31, 2015. We may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments. Settlement of interest rate derivative instruments in a liability position could require a significant amount of cash, which could negatively impact our liquidity and short-term credit availability and increase interest expense over the term of the associated debt.
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

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AVISTA CORPORATION



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 or result in the termination of outstanding regulatory authorizations for certain financing activities.
Credit risk may be affected by industry concentration and geographic concentration.
We have concentrations of suppliers and customers in the electric and natural gas industries including:
electric and natural gas utilities,
electric generators and transmission providers,
oil and natural gas producers and pipelines,
financial institutions including commodity clearing exchanges and related parties, and
energy marketing and trading companies.
We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
Utility Regulatory Risk Factors
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 expenses and capital costs for utility operations in the last several years. We have also made significant capital investments into utility plant assets. Our ability to recover these expenses and capital 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 expenses and capital 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 recovery of deferred expenses is disallowed, it could have a negative effect on our operating revenues, net income and cash flows.
In the future, we may no longer meet the criteria for continued application of regulatory accounting practices for all or a portion of our regulated operations.
If we could no longer apply regulatory accounting, we could be:
required to write off our regulatory assets, and
precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future.
See further discussion at "Note 1 of the Notes to Consolidated Financial Statements – Regulatory Deferred Charges and Credits."
Energy Commodity Risk Factors
Energy commodity price changes affect our cash flows and results of operations.
Energy commodity prices can be 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 the nature of the energy-producing assets or through contractual arrangements - however, a significant portion of our energy resource costs are not fixed, and
the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.

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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.
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 are 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 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 cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. 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.
Generation plants may become obsolete. We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. There is the potential that some of our generation sources, such as coal, may become obsolete. This could result in higher commodity costs to customers to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life.
Operational Risk Factors
We are subject to various operational and event risks.
Our operations are subject to operational and event risks that include:
severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;
blackouts or disruptions of interconnected transmission systems (the regional power grid);
unplanned outages at generating plants,

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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,
damage or injuries to third parties caused by our generation, transmission and distribution systems,
natural disasters that can disrupt energy generation, transmission and distribution and general business operations, and
terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize.
Disasters may affect the general economy, financial and capital markets, specific industries, or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, 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.
Damage to facilities may be caused by severe weather, such as snow, ice, wind storms or avalanches. The cost to implement rapid or any repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather.
Adverse impacts may occur at our Alaska operations that could result from an extended outage of their hydroelectric generating resources or its inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel);
AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity from multiple facilities to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two-thirds of AEL&P’s hydroelectric power generation. Any issues that negatively affect AEL&P's ability to generate or transmit power or any decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows.
Compliance Risk Factors
There have been numerous changes in legislation, related administrative rulemakings, 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 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 the long-term global and our utilities' service area 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 could 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 to which 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,

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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 19 of the Notes to Consolidated Financial Statements” for further details of these matters.
Technology Risk Factors
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. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to these same risks and, to the extent of interconnection to our technology, may impact us. Any failure, unexpected, or unauthorized unavailability 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, competitiveness, and result in costly litigation and impact on our results of operations. 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.
Terrorist attacks could also be directed at physical electric and natural gas facilities, as well as technology systems.
We may be adversely affected by our inability to successfully implement certain technology projects.
We are currently investigating whether to replace all of our electric meter infrastructure in Washington State with advanced metering infrastructure (AMI). If we were to proceed with this AMI project, there is the potential that the costs associated with retiring our current meters could be disallowed by regulators. There is also the risk that regulators will not allow the full recovery of new AMI if we proceed with the project. In addition, there are inherent risks associated with replacing and changing these types of systems, such as incorrect or nonfunctioning metering and/or delayed or inaccurate customer bills or unplanned outages, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Strategic Risk Factors
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 and the extent of our business development efforts where potential future business is uncertain.
Our strategic business plans could be affected by or result in any of the following:
disruptive innovations in the marketplace may outpace our ability to compete or manage our risk,
potential difficulties 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

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potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with our Company.
Our acquisition of AERC may not achieve its intended results.
On July 1, 2014, we acquired AERC, and its subsidiary, AEL&P, the sole provider of electric services in Juneau, Alaska. Achieving the anticipated earnings contribution from AERC is subject to numerous uncertainties, including market conditions and risks related to AERC's business. This transaction could result in increased costs, decreases in the expected revenues from AERC, the impairment of goodwill or other assets, and diversion of management time and resources, which could have a material adverse effect on our results of operations, financial condition and cash flows.
External Mandates Risk Factors
External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact our Company. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Contingencies" and "Forward-Looking Statements" for discussion of or reference to external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows.
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 SEC.

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ITEM 2. PROPERTIES
AVISTA UTILITIES
Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s 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) (3)
4
 
26.4

 
19.5

Upper Falls (Spokane)
1
 
10.0

 
10.2

Monroe Street (Spokane)
1
 
14.8

 
15.0

Idaho:
 
 
 
 
 
Cabinet Gorge (Clark Fork) (4)
4
 
265.0

 
273.0

Post Falls (Spokane)
6
 
14.8

 
15.4

Montana:
 
 
 
 
 
Noxon Rapids (Clark Fork)
5
 
487.8

 
562.4

Total Hydroelectric
 
 
920.8

 
1,019.1

Thermal Generating Stations (cycle, fuel source)
 
 
 
 
 
Washington:
 
 
 
 
 
Kettle Falls GS (combined-cycle, wood waste) (5)
1
 
50.7

 
53.5

Kettle Falls CT (combined-cycle, natural gas) (5)
1
 
7.2

 
6.9

Northeast CT (simple-cycle, natural gas)
2
 
61.8

 
64.8

Boulder Park GS (simple-cycle, natural gas)
6
 
24.6

 
24.0

Idaho:
 
 
 
 
 
Rathdrum CT (simple-cycle, natural gas)
2
 
166.5

 
166.5

Montana:
 
 
 
 
 
Colstrip Units 3 and 4 (simple-cycle, coal) (6)
2
 
233.4

 
222.0

Oregon:
 
 
 
 
 
Coyote Springs 2 (combined-cycle, natural gas)
1
 
287.0

 
284.4

Total Thermal
 
 
831.2

 
822.1

Total Generation Properties
 
 
1,752.0

 
1,841.2


(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, 2015.
(3)
There are four units at the Nine Mile plant; however, Units 1 and 2 are not operating due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two operating units, which have a nameplate rating of 18 MW combined.
(4)
For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.
(5)
These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency.

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(6)
Jointly owned; data refers to our 15 percent interest.
Electric Distribution and Transmission Plant
Avista Utilities owns and operates approximately 19,000 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 1,565 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 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
Avista Utilities has natural gas distribution mains of approximately 3,400 miles in Washington, 2,000 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 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 Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See "Part 1 – Item 1. Business – Avista Utilities – Natural Gas Operations" for further discussion of Jackson Prairie.

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ALASKA ELECTRIC LIGHT AND POWER COMPANY
Substantially all of AEL&P's utility properties are subject to the lien of the AEL&P mortgage indenture.
AEL&P's utility electric properties, located in Alaska include the following:
Generation Properties and Transmission and Distribution Lines
 
No. of
Units
 
Nameplate
Rating
(MW) (1)
 
Present
Capability
(MW) (2)
Hydroelectric Generating Stations
 
 
 
 
 
Snettisham (3)
3
 
78.2

 
78.2

Lake Dorothy
1
 
14.3

 
14.3

Salmon Creek
1
 
8.4

 
5.0

Annex Creek
2
 
4.1

 
3.6

Gold Creek
3
 
1.6

 
1.6

Total Hydroelectric
 
 
106.6

 
102.7

Diesel Generating Stations
 
 
 
 
 
Lemon Creek
11
 
61.4

 
57.5

Auke Bay
3
 
36.2

 
28.3

Gold Creek
5
 
8.2

 
8.1

Total Diesel
 
 
105.8

 
93.9

Total Generation Properties
 
 
212.4

 
196.6

(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, 2015.
(3)
AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for (whether or not energy is received), all of the capacity and energy of this facility. See further information at "Part 1. Item 1. Business – Alaska Electric Light and Power Company."
In addition to the generation properties above, AEL&P owns approximately 61 miles of transmission lines, which is primarily comprised of 69 kV line, and approximately 184 miles of distribution lines.
ITEM 3. LEGAL PROCEEDINGS
See “Note 19 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Avista Corp. Market Information and Dividend Policy
Avista Corp.'s common stock is listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2016, there were 8,753 registered shareholders of our common stock.
Avista Corp.'s 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.
Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).

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The payment of dividends on common stock could be limited by:
certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Level Summary and Capital Resources" for compliance with these covenants),
the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”),
certain requirements under the OPUC approval of the AERC acquisition. The OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured, and
certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding).
On February 5, 2016, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3425 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 3.8 percent from the previous quarterly dividend of $0.33 per share.
For additional information, see “Notes 1, 17 and 18 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
2015
 
 
 
 
 
 
 
Dividends paid per common share
$
0.33

 
$
0.33

 
$
0.33

 
$
0.33

Trading price range per common share:
 
 
 
 
 
 
 
High
$
38.30

 
$
34.25

 
$
33.99

 
$
36.06

Low
$
32.22

 
$
30.41

 
$
29.93

 
$
32.86

2014
 
 
 
 
 
 
 
Dividends paid per common share
$
0.3175

 
$
0.3175

 
$
0.3175

 
$
0.3175

Trading price range per common share:
 
 
 
 
 
 
 
High
$
30.83

 
$
33.58

 
$
33.60

 
$
37.37

Low
$
27.71

 
$
30.02

 
$
30.35

 
$
30.55

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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AVISTA CORPORATION



ITEM 6. SELECTED FINANCIAL DATA
 
(in thousands, except per share data and ratios)
Years Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Operating Revenues:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
1,411,863

 
$
1,413,499

 
$
1,403,995

 
$
1,354,185

 
$
1,443,322

AEL&P
44,778

 
21,644

 

 

 

Other
28,685

 
39,219

 
39,549

 
38,953

 
40,410

Intersegment eliminations
(550
)
 
(1,800
)
 
(1,800
)
 
(1,800
)
 
(1,800
)
Total
$
1,484,776

 
$
1,472,562

 
$
1,441,744

 
$
1,391,338

 
$
1,481,932

Income (Loss) from Operations (pre-tax):
Avista Utilities
$
241,228

 
$
239,976

 
$
232,572

 
$
188,778

 
$
202,373

AEL&P
14,072

 
6,221

 

 

 

Other
(2,086
)
 
6,391

 
(1,483
)
 
(1,680
)
 
4,714

Total
$
253,214

 
$
252,588

 
$
231,089

 
$
187,098

 
$
207,087

Net income from continuing operations
$
118,170

 
$
119,866

 
$
104,333

 
$
76,803

 
$
90,658

Net income from discontinued operations
5,147

 
72,411

 
7,961

 
1,997

 
12,881

Net income
$
123,317

 
$
192,277

 
$
112,294

 
$
78,800

 
$
103,539

Net income attributable to noncontrolling interests
$
(90
)
 
$
(236
)
 
$
(1,217
)
 
$
(590
)
 
$
(3,315
)
Net Income (Loss) attributable to Avista Corporation shareholders:
Avista Utilities
$
113,360

 
$
113,263

 
$
108,598

 
$
81,704

 
$
90,902

AEL&P
6,641

 
3,152

 

 

 

Ecova - Discontinued operations
5,147

 
72,390

 
7,129

 
1,825

 
9,671

Other
(1,921
)
 
3,236

 
(4,650
)
 
(5,319
)
 
(349
)
Net income attributable to Avista Corp. shareholders
$
123,227

 
$
192,041

 
$
111,077

 
$
78,210

 
$
100,224

Average common shares outstanding, basic
62,301

 
61,632

 
59,960

 
59,028

 
57,872

Average common shares outstanding, diluted
62,708

 
61,887

 
59,997

 
59,201

 
58,092

Common shares outstanding at year-end
62,313

 
62,243

 
60,077

 
59,813

 
58,423

Earnings per common share attributable to Avista Corp. shareholders, basic:
Earnings per common share from continuing operations
$
1.90

 
$
1.94

 
$
1.74

 
$
1.30

 
$
1.56

Earnings per common share from discontinued operations
0.08

 
1.18

 
0.11

 
0.02

 
0.17

Total earnings per common share attributable to Avista Corp. shareholders, basic
$
1.98

 
$
3.12

 
$
1.85

 
$
1.32

 
$
1.73

Earnings per common share attributable to Avista Corp. shareholders, diluted:
Earnings per common share from continuing operations
$
1.89

 
$
1.93

 
$
1.74

 
$
1.30

 
$
1.56

Earnings per common share from discontinued operations
0.08

 
1.17

 
0.11

 
0.02

 
0.16

Total earnings per common share attributable to Avista Corp. shareholders, diluted
$
1.97

 
$
3.10

 
$
1.85

 
$
1.32

 
$
1.72

 
 
 
 
 
 
 
 
 
 

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AVISTA CORPORATION



(in thousands, except per share data and ratios)
Years Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Dividends declared per common share
$
1.32

 
$
1.27

 
$
1.22

 
$
1.16

 
$
1.10

Book value per common share
$
24.53

 
$
23.84

 
$
21.61

 
$
21.06

 
$
20.30

Total Assets at Year-End:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
4,601,708

 
$
4,357,760

 
$
3,930,251

 
$
3,883,602

 
$
3,797,160

AEL&P
265,735

 
263,070

 

 

 

Other
39,206

 
80,141

 
81,282

 
95,638

 
112,145

Total (1) (2)
$
4,906,649

 
$
4,700,971

 
$
4,011,533

 
$
3,979,240

 
$
3,909,305

Long-Term Debt and Capital Leases (including current portion) (2)
$
1,573,278

 
$
1,487,126

 
$
1,262,036

 
$
1,217,520

 
$
1,165,014

Nonrecourse Long-Term Debt of Spokane Energy (including current portion)
$

 
$
1,431

 
$
17,838

 
$
32,803

 
$
46,471

Long-Term Debt to Affiliated Trusts
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

Total Avista Corp. Shareholders’ Equity
$
1,528,626

 
$
1,483,671

 
$
1,298,266

 
$
1,259,477

 
$
1,185,701

Ratio of Earnings to Fixed Charges (3)
3.13

 
3.39

 
3.02

 
2.48

 
2.81

(1)
The total assets at year-end for the years 2013 to 2011 exclude the total assets associated with Ecova of $339.6 million, $322.7 million and $292.9 million, respectively.
(2)
The total assets and total long-term debt and capital leases for 2014 through 2011 were adjusted due to the adoption of ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of the adoption of this ASU.
(3)
See Exhibit 12 for computations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Business Segments
As of December 31, 2015, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See "Part I, Item 1. Business – Company Overview" for further discussion of our business segments.
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):
 
2015
 
2014
 
2013
Avista Utilities
$
113,360

 
$
113,263

 
$
108,598

AEL&P
6,641

 
3,152

 

Ecova - Discontinued operations (1)
5,147

 
72,390

 
7,129

Other
(1,921
)
 
3,236

 
(4,650
)
Net income attributable to Avista Corporation shareholders
$
123,227

 
$
192,041

 
$
111,077

(1)
The results for the year ended December 31, 2014 include the net gain on sale of Ecova of $69.7 million.
Executive Level Summary
Overall Results
Net income attributable to Avista Corp. shareholders was $123.2 million for 2015, a decrease from $192.0 million for 2014. The decrease was primarily due to the disposition of Ecova during 2014, which resulted in the recognition of a $74.8 million net gain, with $69.7 million being recognized in 2014 and the remainder being recognized in 2015. Avista Utilities' earnings increased slightly primarily due to the implementation of a general rate increase in Washington, lower net power supply costs, a decrease in the provision for earnings sharing in Idaho and increased cooling loads during the summer. This was mostly offset by weather that was significantly warmer than normal and warmer than the prior year in the first quarter, which reduced heating loads, which was partially offset by the new decoupling mechanism in Washington (implemented January 1, 2015). Also, we

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AVISTA CORPORATION



experienced expected increases in other operating expenses, depreciation and amortization, taxes other than income taxes, and interest expense.
Results for 2015 also include earnings at AEL&P for the full period, whereas 2014 results only include AEL&P for the third and fourth quarters.
Results for 2014 include a $9.8 million net gain at Avista Energy related to the settlement of the California power markets litigation. The net gain from the litigation settlement was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation, a charitable organization funded by Avista Corp. Both of these transactions are reflected in the results of the other businesses.
Avista Utilities
Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things:
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,
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.
Forecasted Customer and Load Growth
Based on our forecast for 2016 through 2019 for Avista Utilities' service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.1 percent, within a forecast range of 0.6 percent to 1.6 percent. We anticipate retail electric load growth to average 0.7 percent, within a forecast range of 0.4 percent and 1.0 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth.
In AEL&P's service area, we expect annual residential customer growth to be in a narrow range around 0.4 percent for 2016 through 2019. We expect no significant growth in commercial and government customers over the same period. We anticipate that average annual total load growth will be in a narrow range around 0.6 percent, with residential load growth averaging 0.6 percent; commercial 0.8 percent; and government 0 percent (no load growth). 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."
See also "Competition" for a discussion of competitive factors that could affect our results of operations in the future.
Capital Expenditures
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. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2015 (in thousands):
 
Avista Utilities
 
AEL&P
2015 Actual capital expenditures
 
 
 
Capital expenditures (per the Consolidated Statement of Cash Flows)
381,174

 
12,251

 
 
 
 
Expected total annual capital expenditures (by year)
 
 
 
2016
375,000

 
17,000

2017
405,000

 
13,000

2018
405,000

 
18,000


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AVISTA CORPORATION



Avista Utilities' 2015 calendar year capital costs, including capital costs of approximately $35.2 million that was unpaid for and accrued in accounts payable as of December 31, 2015, were $415.9 million.
These estimates of capital expenditures are subject to continuing review and adjustment.
Alaska Energy and Resources Company Acquisition
On July 1, 2014, we acquired AERC, based in Juneau, Alaska. The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 does not contain any financial results from AERC. This transaction resulted in the recording of $52.4 million in goodwill. For additional information regarding the AERC transaction, including pro forma financial comparisons, see “Note 4 of the Notes to Consolidated Financial Statements.”
Ecova Disposition
On June 30, 2014, Avista Capital completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, for a sales price of $335.0 million in cash, less the payment of debt and other customary closing adjustments. The sale of Ecova provided total cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some minor true-ups during 2015.
The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 contains the financial results of Ecova (in discontinued operations) and 2015 does not have any material results from Ecova. For additional information regarding the Ecova disposition, see “Note 5 of the Notes to Consolidated Financial Statements.”
Stock Repurchase Programs
During 2014, Avista Corp. repurchased 2,529,615 shares of our outstanding common stock at a total cost of $79.9 million and an average cost of $31.57 per share through our 2014 stock repurchase program. We did not make any repurchases under this program subsequent to October 2014 and the program expired on December 31, 2014.
In the first quarter of 2015, Avista Corp. repurchased 89,400 shares of our outstanding common stock at a total cost of $2.9 million and an average cost of $32.66 per share under a second stock repurchase program that expired on March 31, 2015. All repurchased shares reverted to the status of authorized but unissued shares.
Wind Storm
On November 17, 2015, a historic wind storm occurred in our service territory. The storm had wind speeds exceeding 70 miles per hour which knocked down numerous trees and power poles and caused severe damage to our electrical system. Most of the damage occurred in Spokane County. The storm resulted in significant customer power outages and at the height of the storm approximately 180,000 customers (about 48 percent of our total retail electric customers) were without power, causing the most significant damage and the highest number of customer outages Avista Utilities has ever experienced. It took Avista Utilities crews from throughout the region, along with contract and mutual aid crews, approximately 10 days to fully restore power to all affected customers. Most of the storm-related costs incurred were capital costs (labor and materials) to repair the electrical system, but there were also operating and maintenance costs. The capital repair costs for power restoration were $22.9 million and $2.9 million for incremental utility operating and maintenance costs. In addition, there was approximately $0.4 million of incremental nonutility operating and maintenance costs. The damage and restoration costs were primarily incurred in Washington state and we plan to include the incremental operating and maintenance costs in the calculations for earnings sharing (see "Regulatory Matters – Decoupling and Earnings Sharing Mechanisms" for further discussion of the earnings sharing mechanisms).
Liquidity and Capital Resources
Avista Corp. has a $400.0 million committed line of credit with various financial institutions that expires in April 2019. We have an option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. As of December 31, 2015, there were $105.0 million of cash borrowings and $44.6 million in letters of credit outstanding, leaving $250.4 million of available liquidity under this line of credit.
The Avista Corp. facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2015, we were in compliance with this covenant with a ratio of 53.1 percent.
AEL&P has a $25.0 million committed line of credit which expires in November 2019. As of December 31, 2015, there were no borrowings or letters of credit outstanding under this committed line of credit.

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AVISTA CORPORATION



The AEL&P committed line of credit agreement contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2015, AEL&P was in compliance with this covenant with a ratio of 57.2 percent.
In December 2015, we issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. In connection with this pricing, we cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. Upon settlement of 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 term of the associated debt.
In 2015, we issued $1.6 million (net of issuance costs) of common stock under the employee plans.
For 2016, we expect to issue approximately $155.0 million of long-term debt and $55.0 million of common stock in order to maintain an appropriate capital structure and to fund planned capital expenditures.
After considering the expected issuances of long-term debt and common stock during 2016, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.
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:
seek recovery of operating costs and capital investments, and
seek the opportunity to earn reasonable 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 major revenue and expense items.
Washington General Rate Cases
2012 General Rate Cases
In December 2012, the UTC approved a settlement agreement in Avista Utilities' electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013 provided that base rates for our Washington electric customers increase 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 approved settlement also provided that, effective January 1, 2014, base rates increase for our Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and increase for our Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million).
The settlement agreement provided for an authorized return on equity (ROE) of 9.8 percent and an equity ratio of 47 percent, resulting in an overall rate of return on rate base (ROR) of 7.64 percent.
2014 General Rate Cases
In November 2014, the UTC approved an all-party settlement agreement related to Avista Utilities' electric and natural gas general rate cases filed in February 2014 and new rates became effective on January 1, 2015. The settlement was designed to increase annual electric base revenues by $12.3 million, or 2.5 percent, inclusive of a $5.3 million power supply update as required in the settlement agreement (explained below). The settlement was designed to increase annual natural gas base revenues by $8.5 million, or 5.6 percent. The settlement agreement also included the implementation of decoupling mechanisms for electric and natural gas and a related after-the-fact earnings test. See "Decoupling and Earnings Sharing Mechanisms" below for further discussion of these mechanisms.
Specific capital structure ratios and the cost of capital components were not agreed to in the settlement agreement. The revenue increases in the settlement were not tied to the 7.32 percent ROR used in conjunction with the after-the fact earnings test discussed under "Decoupling and Earnings Sharing Mechanisms" below. The electric and natural gas revenue increases were negotiated numbers, with each party using its own set of assumptions underlying its agreement to the revenue increases. The parties agreed that the 7.32 percent ROR will be used to calculate the AFUDC and other purposes.

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AVISTA CORPORATION



2015 General Rate Cases
In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the UTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.
The UTC approved rates designed to provide a 1.6 percent, or $8.1 million decrease in electric base revenue, and a 7.4 percent, or $10.8 million increase in natural gas base revenue. The UTC also approved an ROR on rate base of 7.29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent ROE.
Throughout the rate case process, certain circumstances and costs changed, causing us to revise our overall proposed rate requests downward, especially for our electric operations. Our need for electric rate relief was reduced primarily due to the following:
a decrease in power supply costs of approximately $24.0 million caused by the continuing decline in the price of natural gas used to run our natural gas-fired generation and lower contract costs associated with a new PPA from Chelan PUD,
updated information related to federal tax adjustments and state allocations,
the delay in the expected completion date of the Nine Mile hydroelectric generation project upgrade from late 2015 to late 2016, and
a delay of the start date to begin amortization of existing electric meters from 2016 to a future year, associated with our proposed AMI project.
The natural gas revenue increase approved by the UTC is related to our ownership and operating costs to run the natural gas business. Changes in the commodity costs of natural gas for natural gas customers are reflected in our annual PGA, which is generally effective November 1st each year. On November 1, 2015 natural gas customers’ bills were reduced approximately 15 percent related to the decline in the market price of natural gas.
In responsive testimony filed by the UTC Staff in July 2015 in our electric and natural gas general rate cases, they recommended a disallowance of $12.7 million (Washington's share) of the costs associated with the replacement of our customer information and work management systems (Project Compass) primarily related to the delay in the completion of the project. In the January 6, 2016 UTC order, they approved the full recovery of Washington's portion of Project Compass costs.
UTC issues Order denying Industrial Customers of Northwest Utilities / Public Counsel Joint Motion for Clarification, UTC Staff Motion to Reconsider and UTC Staff Motion to Reopen Record
On February 19, 2016, the UTC issued an order denying the Motions summarized below and affirmed their original January 2016 order of an $8.1 million decrease in electric base revenue, thus finalizing our 2015 electric and natural gas general rate cases.
On January 19, 2016, the Industrial Customers of Northwest Utilities (ICNU) and the Public Counsel Unit of the Washington State Office of the Attorney General (PC) filed a Joint Motion for Clarification with the UTC. In its Motion for Clarification, ICNU and PC requested that the UTC clarify the calculation of the electric attrition adjustment and the end-result revenue decrease of $8.1 million. ICNU and PC provided their own calculations in their Motion, and suggested that the revenue decrease should have been $19.8 million based on their reading of the UTC’s Order.
On January 19, 2016, the UTC Staff, which is a separate party in the general rate case proceedings from the UTC Advisory Staff that supports the Commissioners, filed a Motion to Reconsider with the UTC. In its Motion to Reconsider, the Staff provided calculations and explanations that suggested that the electric revenue decrease should have been a revenue decrease of $27.4 million instead of $8.1 million, based on its reading of the UTC's Order. Further, on February 4, 2016, the UTC Staff filed a Motion to Reopen Record for the Limited Purpose of Receiving into Evidence Instruction on Use and Application of Staff’s Attrition Model, and sought to supplement the record “to incorporate all aspects of the Company’ Power Cost Update.” Within this Motion, UTC Staff updated its suggested electric revenue decrease to $19.6 million.
None of the parties in their Motions raised issues with the UTC’s decision on the natural gas revenue increase of $10.8 million.

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AVISTA CORPORATION



Petition for an Accounting Order to Defer Existing Washington Electric Meters
In January 2016, we filed a Petition with the UTC for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for later recovery. This requested accounting treatment is related to our plans to replace approximately 253,000 of our existing electric meters with new two-way digital meters through our Advanced Metering Infrastructure (AMI) project in Washington state.
The petition requests that the UTC allow the deferral, with prudence of the overall AMI project and ultimate recovery, to be addressed in a future regulatory proceeding. The undepreciated value estimated for this deferred accounting treatment is approximately $18.6 million. We have requested recovery of this regulatory asset, with a full rate of return, over fifteen years starting in January 2017, within our February 19, 2016 general rate case filing.
2016 General Rate Cases
On February 19, 2016, we filed electric and natural gas general rates cases with the UTC. Our proposal includes an 18-month rate plan, with new rates taking effect on January 1, 2017 and January 1, 2018. Under this plan, we would not file a future rate case for new rates to be effective prior to July 1, 2018.
The 2017 increase, if approved, would increase overall base electric rates 7.8 percent (designed to increase annual electric revenues by $38.6 million) and overall base natural gas rates 5.0 percent (designed to increase annual natural gas revenues by $4.4 million).
In addition, we have requested a second step increase effective January 1, 2018, which would increase overall base electric rates by 3.9 percent (designed to increase annual electric revenues by $10.3 million) and overall base natural gas rates by 1.8 percent (designed to increase annual natural gas revenues by $0.9 million). We have proposed to offset the electric increase, for the period January through June 2018, with available ERM dollars. As a result, customers would not see an electric general rate case bill increase in 2018 prior to July 1, 2018.
Our requests are based on a proposed ROR on rate base of 7.64 percent with a common equity ratio of 48.5 percent and a 9.9 percent ROE.
The UTC has up to 11 months to review the filings and issue a decision.
Idaho General Rate Cases
2012 General Rate Cases
In March 2013, the IPUC approved a settlement agreement in Avista Utilities' electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for our Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013.
The settlement also provided that, effective October 1, 2013, base rates increased for our Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million).
Further, the settlement provided that, effective October 1, 2013, base rates increased for our Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million).
The settlement agreement provided for an authorized ROE of 9.8 percent and an equity ratio of 50.0 percent.
2014 Rate Plan Extension
Avista Utilities did not file new general rate cases in Idaho in 2014; instead, we developed an extension to the 2013 and 2014 rate plan and reached a settlement agreement with all interested parties.
In September 2014, the IPUC approved the settlement, which reflected agreement among all interested parties, for a one-year extension to our current rate plan, which was set to expire on December 31, 2014. Under the approved extension, base retail rates remained unchanged through December 31, 2015.
The settlement provided an estimated $3.7 million increase in pre-tax income by reducing planned expenses in 2015 for our Idaho operations.

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2015 General Rate Cases
In December 2015, the IPUC approved a settlement agreement between Avista Utilities and all interested parties related to our electric and natural gas general rate cases, which were originally filed with the IPUC on June 1, 2015. New rates were effective on January 1, 2016.
The settlement agreement is designed to increase annual electric base revenues by $1.7 million or 0.7 percent and annual natural gas base revenues by $2.5 million or 3.5 percent. The settlement is based on a ROR of 7.42 percent with a common equity ratio of 50 percent and a 9.5 percent ROE.
The settlement agreement also reflects the following:
the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and
the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed below.
2016 General Rate Cases
We expect to file electric and natural gas general rate cases in Idaho during the first half of 2016.
Oregon General Rate Cases
2013 General Rate Case
In January 2014, the OPUC approved a settlement agreement in Avista Utilities' natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates were implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $3.8 million). Effective November 1, 2014, rates for Oregon natural gas customers were to increase on a billed basis by an overall 1.6 percent (designed to increase annual revenues by $1.4 million).
The billed rate increase on November 1, 2014 was dependent upon the completion of Project Compass and the actual costs incurred through September 30, 2014, and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. Project Compass was completed in February 2015. The November 1, 2014 rate increase was reduced from $1.4 million to $0.3 million due to the delay of Project Compass.
The approved settlement agreement provides for an overall authorized ROR of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent ROE.
2014 General Rate Case
In January 2015, Avista Utilities filed an all-party settlement agreement with the OPUC related to our natural gas general rate case, which was originally filed in September 2014. On February 23, 2015, the OPUC issued an order rejecting the all-party settlement agreement. The OPUC expressed concerns related to, among other things, various rate design issues.
In March 2015, Avista Utilities filed an amended all-party settlement agreement with the OPUC which addressed the OPUC's concerns regarding the initial settlement agreement. The amended settlement agreement was designed to increase base natural gas revenues by $5.3 million. Included in this base rate increase is $0.3 million in base revenues that we are already receiving from customers through a separate rate adjustment. Therefore, the net increase in base revenues was $5.0 million, or 4.9 percent on a billed basis. The parties requested that new retail rates become effective on April 16, 2015. On April 9, 2015, the OPUC issued an Order approving the amended settlement agreement as filed.
This settlement agreement provided for an overall authorized ROR of 7.516 percent with a common equity ratio of 51 percent and a 9.5 percent ROE.
2015 General Rate Case
On May 1, 2015, we filed a natural gas general rate case with the OPUC. We have requested an overall increase in base natural gas rates of 8 percent (designed to increase annual natural gas revenues by $8.6 million). Our request is based on a proposed ROR on rate base of 7.72 percent with a common equity ratio of 50 percent and a 9.9 percent ROE.
Avista Corp. and all parties to our natural gas general rate case reached agreement on certain issues, and a partial settlement agreement was filed with the OPUC in November 2015. The partial settlement agreement reduced our requested natural gas revenue increase from $8.6 million to $6.7 million or 6.3 percent. The partial settlement, if approved by the OPUC, would resolve a number of issues including the calculation of state income taxes for rate-making purposes, wages and salaries, the revenue forecast for the rate period, and working capital. The agreement does not resolve other issues including the appropriate ROE and capital structure, the appropriate level of additions to rate base, and medical and pension expenses. In January 2016,

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we entered into an additional all-party partial settlement to further reduce our revenue increase request to $6.1 million, related to updated information related to deferred taxes and its effect on rate base.
The agreement includes a provision for the implementation of a decoupling mechanism, similar to the Washington and Idaho mechanisms described above.
In addition to the partial settlement agreements above, the OPUC staff filed testimony which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs primarily related to the delay in the full completion of the project. In January 2016, following the January 6, 2016 UTC order approving the full recovery of Washington's portion of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion.
The procedural schedule includes an expected decision from the OPUC by February 29, 2016.
Alaska General Rate Case
AEL&P's last general rate case was filed in 2010 and approved by the RCA in 2011. We are evaluating the need to file an electric general rate case with the RCA in 2016.
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a liability of $17.9 million as of December 31, 2015 and a liability of $3.9 million as of December 31, 2014.
The following PGAs went into effect in our various jurisdictions during 2013, 2014 and 2015:
Jurisdiction
 
PGA Effective Date
 
Percentage Increase / (Decrease) in Billed Rates
Washington
 
November 1, 2013
 
9.2%
 
 
November 1, 2014
 
1.2%
 
 
November 1, 2015
 
(15.0)%
Idaho
 
October 1, 2013
 
7.5%
 
 
November 1, 2014
 
(2.1)%
 
 
November 1, 2015
 
(14.5)%
Oregon
 
November 1, 2013
 
(7.9)%
 
 
November 1, 2014
 
8.3%
 
 
November 1, 2015
 
(14.1)%
Power Cost Deferrals and Recovery Mechanisms
The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Total net deferred power costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers.
The difference in net power supply costs under the ERM primarily results from changes in:
short-term wholesale market prices and sales and purchase volumes,
the level and availability of hydroelectric generation,
the level and availability of thermal generation (including changes in fuel prices), and
retail loads.
Under the ERM, Avista Utilities absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million.

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