10-K 1 ava-20171231x10k.htm 10-K Document
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, 2017 OR
o
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  o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  o    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  o
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  o
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.  o



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
x
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
o
Emerging growth company
o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  o    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 $2,734,805,418 based on the last reported sale price thereof on the consolidated tape on June 30, 2017.
As of January 31, 2018, 65,628,172 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 10, 2018.
Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 11, 2017.
 
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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7A.
 
 
8.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9.
 
*
9A.
 
 
9B.
 
 
 
 
Part III
 
 
10.
 
 
11.
 
 

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 * = not an applicable item in the 2017 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
ARAM
-
Average Rate Assumption Method
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
CIAC
-
Contribution in aid of construction
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 subsidiary of Avista Capital until June 30, 2014 when it was sold.
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
FCA
-
Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho.
FERC
-
Federal Energy Regulatory Commission
GAAP
-
Generally Accepted Accounting Principles
GHG
-
Greenhouse gas
GS
-
Generating station
Hydro One
-
Hydro One Limited, based in Toronto, Ontario, Canada.
IPUC
-
Idaho Public Utilities Commission

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IRP
-
Integrated Resource Plan
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
LNG
-
Liquefied Natural Gas
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
PPA
-
Power Purchase Agreement
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
Salix
-
Salix, Inc., a subsidiary of Avista Capital, launched in 2014 to explore markets that could be served with 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.
TCJA
-
The "Tax Cuts and Jobs Act," signed into law on December 22, 2017.
Therm
-
Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
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
WUTC
-
Washington Utilities and Transportation Commission

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Forward-Looking Statements
From time-to-time, we make forward-looking statements such as statements regarding projected or future:
financial performance;
cash flows;
capital expenditures;
dividends;
capital structure;
other financial items;
strategic goals and objectives;
business environment; and
plans for operations.
These statements 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, 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 to which we recover interest costs through retail rates collected from customers;
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;
deterioration in the creditworthiness of our customers;
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 long-term climates, both globally and within our utilities' service areas, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;
Utility Regulatory Risk
state and federal regulatory decisions or related judicial 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, commodity costs, interest rate swap derivatives and discretion over allowed return on investment;

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possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions, which could result in future resource acquisitions based on the integrated resource plans that are later deemed imprudent;
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 environmental regulations affecting our ability to utilize or resulting in the obsolescence of our power supply resources;
Operational Risk
severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, 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 electric and natural gas distribution systems or other operations and may require us to purchase replacement power;
explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that may cause wildfires, injuries to the public or property damage;
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 or regional 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;
increasing health care costs and cost of health insurance provided to our employees and retirees;
third party construction of buildings, billboard signs, towers or other structures 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;
adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel);
changing river regulation at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;
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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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 costs that impede our ability to effectively implement new information technology systems or to operate and maintain current production technology;
changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks;
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;
the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and 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;
non-regulated activities may increase earnings volatility;
failure to complete the proposed acquisition of the Company by Hydro One, which would negatively impact the market price of Avista Corp.'s common stock and could result in termination fees that would have a material adverse effect on our results of operations, financial condition, and cash flows;
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 initiatives, 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 distribution systems through accelerated adoption of distributed generation or electric-powered transportation or 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 to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business;
the new federal income tax law and its intended and unintended consequences on financial results and future cash flows, including the potential impact to credit ratings, which may affect our ability to borrow funds or increase the cost of borrowing in the future;
policy and/or legislative changes resulting from the current presidential administration in various regulated areas, including, but not limited to, environmental regulation and healthcare regulations; 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 reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. There

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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.
Available Information
Our website address is www.avistacorp.com. We make annual, quarterly and current reports available on our website as soon as practicable after electronically filing these reports with the U.S. Securities and Exchange Commission (SEC). Information contained on our website is not part of this report. 
PART I
ITEM 1. BUSINESS
COMPANY OVERVIEW
Avista Corp., 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, 2017, we employed 1,744 people in our Pacific Northwest utility operations (Avista Utilities) and 204 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 Juneau, Alaska.
As of December 31, 2017, we have two reportable business segments as follows:
Avista Utilities – an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' 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 its load-serving obligation.
AEL&P - a utility providing electric services in Juneau, Alaska that is a wholly-owned subsidiary and the primary operating subsidiary of AERC.
We have other businesses, including sheet metal fabrication, venture fund investments, real estate investments, 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.
Total Avista Corp. shareholders’ equity was $1,729.8 million as of December 31, 2017, of which $52.6 million represented our investment in Avista Capital and $108.6 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 2017, Avista Utilities supplied retail electric service to approximately 382,000 customers and retail natural gas service to approximately 347,000 customers across its 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.

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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.
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 of energy resources from those available to serve our load obligations and the capture of additional economic value through wholesale market transactions. These transactions include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, fuel and fuel transportation. Such transactions are part of the process of matching available resources with load obligations and hedging the related financial risks. In order to implement this process, 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. The process of 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, and the terms range from intra-hour up to multiple years.
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. We acquire 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 2017 was 1,681 MW, which occurred on January 5, 2017. In 2016, our peak electric native load was 1,655 MW, which occurred during the winter, and in 2015, it was 1,638 MW, which occurred during the summer.
Electric Resources
Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric, thermal and wind generation facilities, and other contracts for power purchases and exchanges.
At the end of 2017, our Company-owned facilities had a total net capability of 1,875 MW, of which 56 percent was hydroelectric and 44 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 electric energy 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

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generation for 2018 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 547 aMW (or 4.8 million MWhs).
The following graph shows Avista Utilities' hydroelectric generation (in thousands of MWhs) during the year ended December 31:
chart-f0b70f51cdf1500681b.jpg
(1)
Normal hydroelectric generation is determined by reference to the effect of upstream dam regulation on median natural water flow. 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 generating 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 GS and Kettle Falls CT).
Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under a combination of term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.
Colstrip, which is operated by Talen Montana, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2029. In addition, see “Item 7. Management's Discussion and Analysis, Environmental Issues and Contingencies" for further discussion regarding environmental issues surrounding Colstrip.

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The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.
The Northeast CT, Rathdrum CT, Boulder Park GS 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.
We have the exclusive rights to all the 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 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:
chart-c3f78779c42852aea35.jpg
Wind Resources We have exclusive rights to all the capacity of Palouse Wind, a wind generation project developed, owned and managed by an unrelated third-party and located in Whitman County, Washington. We have a PPA that expires in 2042 that requires us 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 105 MW. Generation from Palouse Wind was 300,380 MWhs in 2017, 349,771 MWhs in 2016 and 293,563 MWhs in 2015. We have an annual option to purchase the wind project beginning in December 2022. The purchase price 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 PPA. Under the terms of the PPA, we do not have any input into the day-to-day operation of the project, including maintenance decisions. All such rights are held by the owner.
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 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 WUTC and the IPUC.

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See “Avista Utilities Electric Operating Statistics – Electric Operations” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2017, 2016 and 2015. See “Electric Operations” above 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" below for the magnitude of these power purchase and sales contracts in future periods.
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 (Little Falls), 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 by the federal government 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. In the unlikely event that a take-over occurs, it could lead to either the decommissioning of the hydroelectric project or offering the project to another party (likely through sale and transfer of the license).
Cabinet Gorge and Noxon Rapids are under one 45-year FERC license issued in 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 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 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 1,070 aMW in 2017, 1,033 aMW in 2016 and 1,047 aMW in 2015.
The following graph shows our forecast of our average annual energy requirements and our available resources for 2018 through 2021:
chart-6be71ee1f7435c908a0.jpg


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AVISTA CORPORATION



(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.
In August 2017, we filed our 2017 Electric IRP with the WUTC and the IPUC. The WUTC and IPUC review the IRPs and give the public the opportunity to comment. The WUTC and IPUC do not approve or disapprove of the content in the IRPs; rather they 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 2017 IRP include the following expectations and/or assumptions:
Our current generation resources will remain cost effective and reliable sources of power to meet future customer needs over the next 20 years.
Energy storage costs are significantly lower than those assumed in the 2015 IRP, which, for the first time, makes the energy storage technology operationally attractive in meeting energy needs in the 20-year timeframe of the 2017 IRP.
A power purchase agreement for a solar facility of at least 15 MW for our new Solar Select Program for commercial and industrial customers.
Conservation will effectively provide 53 percent of the requirements of future load growth.
Colstrip will remain a cost effective and reliable source of power to meet future customer needs.
If Colstrip were retired in 2030, total customer bills would increase approximately $50.0 million in the first year following retirement.
Major changes from the 2015 IRP include the following expectations and/or assumptions:
The 2017 Expected Case energy forecast will grow at 0.47 percent per year, replacing the 0.6 percent annual growth rate in the 2015 IRP. See "Item 7. Management Discussion and Analysis – 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 – 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.
Peak load growth will be lower than energy growth, at 0.42 percent for the winter and 0.46 percent for the summer.
Lower expected load growth combined with recent Mid-Columbia hydroelectric contracts, energy efficiency, and demand response will delay the need for additional resources from the end of 2020 until 2026.
Demand response (temporarily reducing the demand for energy) is a viable strategy for meeting future energy needs and energy storage and solar have been added as future resources.
We expect lower emissions from Avista Corp. owned and controlled resources due to lower utilization of natural-gas fired peaking plants and no new combined-cycle plants.
We are required to file an electric IRP every two years, with the next IRP expected to be filed during the third quarter of 2019. Our resource strategy may change from the 2017 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 affected by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.
While not specifically addressed in the IRP, regionally, there are potential regulatory or legislative initiatives that could introduce carbon pricing or cap-and-trade mechanisms related to greenhouse gas emissions. If any of these initiatives are implemented, they could change the economics associated with operating Colstrip 3 & 4 such that the units are no longer cost effective for future customer needs. We cannot currently determine the likelihood or impact of those initiatives, but we believe if Colstrip 3 & 4 are no longer cost effective, it is reasonable to expect that there would be a regulatory process to address any

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undepreciated assets associated with Colstrip 3 & 4, as well as the costs associated with replacement generation and any other unforeseen closure costs that might be incurred.
See “Item 7. Management’s Discussion and Analysis of Financial Condition – 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 a 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 forward fixed price purchases, index and spot market 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 of our customers' projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future. 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 and 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 WUTC and IPUC staff in semi-annual meetings, and updates are given to the OPUC staff quarterly. Other stakeholders, such as the Public Counsel Unit of the Office of the Attorney General or the 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 deliver 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 are subject to review for prudence 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.

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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 throughout the year by executing transactions that capture favorable market price spreads. Natural gas buyers identify opportunities to purchase lower cost natural gas in the immediate term to inject into storage, and then sell the gas in a forward market to be withdrawn at a later time. The reverse of this type of transaction also occurs. These transactions lock in incremental value for customers. 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 2016, we filed our 2016 Natural Gas IRP with the WUTC, 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.
Highlights of the 2016 natural gas IRP include the following expectations and/or assumptions:
We will 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 will continue to be relatively stable due to robust North American supplies led by shale gas development.
Future customer growth in our service territory will increase slightly compared to the 2014 IRP. There will be increasing interest from customers to utilize natural gas due to its abundant supply and subsequent low cost. We anticipate that any increased demand in the region will primarily come from power generation as natural gas is increasingly being used to back up solar and wind technology, as well as replace retired coal plants. There is also potential for increased usage in other markets, such as transportation and as an industrial feedstock.
The availability of natural gas in North America will continue to change global LNG dynamics. Existing and new LNG facilities will look to export low cost North American natural gas to the higher priced Asian and European markets. This could alter the price of natural gas and/or transportation, constrain existing pipeline networks, stimulate development of new pipeline resources, and change flows of natural gas across North America.
Since 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 a natural gas IRP every two years, with the next IRP expected to be filed during the third quarter of 2018. Our resource strategy in our 2018 IRP may change from the 2016 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 WUTC, IPUC, OPUC and 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” (in addition to being itself an operating utility), 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 jurisdictional state utility commission, 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.

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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 to 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 revenues, operating expenses and net investment for a test year that ended prior to the date of the request, subject to possible adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, operating 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, the denial by the commission of recovery, or timely recovery, of certain expenses or investment and the limitation by the commission of the authorized return on investment.
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 – 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 WUTC and the IPUC. See “Item 7. Management’s Discussion and Analysis – 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.
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 – 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.
Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, each month Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only the residential and commercial customer classes are included in our decoupling mechanisms. In conjunction with the decoupling mechanisms, Washington includes an after-the-fact earnings test. At the end of each calendar year, earnings calculations are made for the prior calendar year and a portion of any earnings above a certain threshold are deferred and later returned to customers. Oregon also has an annual earnings review, not directly associated with the decoupling mechanism, where earnings above a certain threshold are deferred and later returned to customers. See “Item 7. Management’s Discussion and Analysis – Regulatory Matters – Decoupling and Earnings Sharing Mechanisms” for further discussion of these mechanisms.
Federal Laws Related to Wholesale Competition
Federal law promotes practices that foster competition in the electric wholesale energy market. 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.

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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 – Competition” for further information.
Regional Transmission Planning
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 or an independent system operator (ISO).
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 fills the role of facilitating the regional transmission planning requirements of FERC Order No. 1000, and other clarifying FERC Orders, for its members. 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) has an EIM in the western United States. Most investor-owned utilities in the Pacific Northwest are either participants in the CAISO EIM or plan to integrate into the market in the near future. The decision to join the CAISO EIM is based on a number of factors, including the amount of variable generating resources in the utilities’ systems, the ability to manage the variable generating resources within the utilities’ systems, the costs associated with joining the CAISO EIM, and the economic benefits associated with joining the CAISO EIM. We have conducted analyses with respect to joining the CAISO EIM, and we currently do not believe there is a compelling case to do so. As additional utilities join the CAISO EIM, there could be a reduction in bilateral market liquidity and opportunities for wholesale transactions in the Pacific Northwest. 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 FERC approves NERC Reliability Standards, including western region standards that make up the set of legally enforceable standards for the United States bulk electric system. The first of these reliability standards became effective in 2007. From time to time new standards are developed or existing standards are updated, revised, consolidated or eliminated pursuant to an industry-involved process. 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). Failure to comply with NERC reliability standards could result in financial penalties of up to $1 million per day per violation. We have a robust internal compliance program in place to manage compliance activities and mitigate the risk of potential noncompliance with these standards. We do not expect the costs associated with compliance with these standards to have a material impact on our financial results.
Peak Reliability is the reliability coordinator in the Western Interconnection that performs reliability coordinator functions for its funding parties, including Avista Corp. The CAISO, which is a significant Peak Reliability funding party recently submitted its notice of withdrawal from Peak Reliability, effective on September 2, 2019. We are evaluating the impact of CAISO’s

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withdrawal on our cost of obtaining reliability coordinator services, which impact cannot be accurately determined at this time. We are also evaluating all alternatives for obtaining the required reliability coordinator services.
Vulnerability to Cyber Attack
It has been widely reported that the energy sector, particularly electric and natural gas utility companies in the United States and abroad, have become the subject of cyber-attacks with increased frequency. The Company’s administrative and operating networks are targeted by hackers on a regular basis.
A successful attack on the Company’s administrative networks could compromise the security and privacy of data, including operating, financial and personal information. A successful attack on the Company’s operating networks could impair the operation of the Company’s electric and/or natural gas utility facilities, possibly resulting in the inability to provide electric and/or natural gas service for extended periods of time.
The Company continually reinforces and updates its defensive systems and is in compliance with NERC’s reliability standards. See “Reliability Standards," "Item 1A. Risk Factors – Technology Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Enterprise Risk Management – Technology Risks” for further information.

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
 
Years Ended December 31,
 
2017
 
2016
 
2015
ELECTRIC OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
381,682

 
$
339,210

 
$
335,552

Commercial
311,593

 
305,613

 
308,210

Industrial
110,982

 
107,296

 
111,770

Public street and highway lighting
7,484

 
7,662

 
7,277

Total retail
811,741

 
759,781

 
762,809

Wholesale
81,512

 
112,071

 
127,253

Sales of fuel
64,925

 
78,334

 
82,853

Other
31,614

 
28,492

 
25,839

Decoupling
(8,220
)
 
17,349

 
4,740

Provision for earnings sharing
(1,182
)
 
932

 
(5,621
)
Total electric operating revenues
$
980,390

 
$
996,959

 
$
997,873

ENERGY SALES (Thousands of MWhs):
 
 
 
 
 
Residential
3,840

 
3,528

 
3,571

Commercial
3,222

 
3,183

 
3,197

Industrial
1,815

 
1,763

 
1,812

Public street and highway lighting
20

 
23

 
23

Total retail
8,897

 
8,497

 
8,603

Wholesale
2,881

 
2,998

 
3,145

Total electric energy sales
11,778

 
11,495

 
11,748

ENERGY RESOURCES (Thousands of MWhs):
 
 
 
 
 
Hydro generation (from Company facilities)
3,978

 
3,836

 
3,434

Thermal generation (from Company facilities)
3,476

 
3,626

 
3,983

Purchased power
4,809

 
4,597

 
4,899

Power exchanges
(6
)
 
(6
)
 
(2
)
Total power resources
12,257

 
12,053

 
12,314

Energy losses and Company use
(479
)
 
(558
)
 
(566
)
Total energy resources (net of losses)
11,778

 
11,495

 
11,748

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
334,848

 
330,699

 
327,057

Commercial
42,154

 
41,785

 
41,296

Industrial
1,328

 
1,342

 
1,353

Public street and highway lighting
569

 
558

 
529

Total electric retail customers
378,899

 
374,384

 
370,235

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (KWh)
11,469

 
10,667

 
10,827

Revenue per KWh (in cents)
9.94

 
9.62

 
9.40

Annual revenue per customer
$
1,139.87

 
$
1,025.74

 
$
1,017.21

AVERAGE HOURLY LOAD (aMW)
1,070

 
1,033

 
1,047



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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
Years Ended December 31,
 
2017
 
2016
 
2015
RETAIL NATIVE LOAD at time of system peak (MW):
 
 
 
 
 
Winter
1,681

 
1,655

 
1,529

Summer
1,596

 
1,587

 
1,638

COOLING DEGREE DAYS: (1)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
743

 
474

 
805

Historical average
529

 
545

 
545

% of average
140
%
 
87
%
 
148
%
HEATING DEGREE DAYS: (2)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
6,783

 
5,790

 
5,614

Historical average
6,578

 
6,680

 
6,726

% of average
103
%
 
87
%
 
83
%

(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). During 2017, we modified the calculation for historical average cooling degree days. We have recalculated 2016 and 2015 using the updated methodology to be consistent with 2017.
(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). During 2017, we modified the calculation for historical average heating degree days. We have recalculated 2016 and 2015 using the updated methodology to be consistent with 2017.

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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
 
 
Years Ended December 31,
 
2017
 
2016
 
2015
NATURAL GAS OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
220,176

 
$
195,275

 
$
193,825

Commercial
104,240

 
92,978

 
96,751

Interruptible
1,901

 
2,179

 
2,782

Industrial
3,756

 
3,348

 
3,792

Total retail
330,073

 
293,780

 
297,150

Wholesale
142,722

 
153,446

 
204,289

Transportation
9,208

 
8,339

 
7,988

Other
6,412

 
5,787

 
5,578

Decoupling
(11,374
)
 
12,309

 
6,004

Provision for earnings sharing
(2,392
)
 
(2,767
)
 

Total natural gas operating revenues
$
474,649

 
$
470,894

 
$
521,009

THERMS DELIVERED (Thousands of Therms):
 
 
 
 
 
Residential
221,982

 
186,565

 
176,613

Commercial
133,343

 
112,686

 
107,894

Interruptible
5,465

 
5,700

 
4,708

Industrial
6,340

 
5,234

 
5,070

Total retail
367,130

 
310,185

 
294,285

Wholesale
545,348

 
684,317

 
809,132

Transportation
186,222

 
178,377

 
164,679

Interdepartmental and Company use
441

 
378

 
335

Total therms delivered
1,099,141

 
1,173,257

 
1,268,431

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
307,375

 
300,883

 
296,005

Commercial
35,192

 
34,868

 
34,229

Interruptible
37

 
37

 
35

Industrial
251

 
255

 
261

Total natural gas retail customers
342,855

 
336,043

 
330,530

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (therms)
722

 
620

 
593

Revenue per therm (in dollars)
$
0.99

 
$
1.05

 
$
1.10

Annual revenue per customer
$
716.31

 
$
649.01

 
$
650.83

HEATING DEGREE DAYS: (1)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
6,783

 
5,790

 
5,614

Historical average
6,578

 
6,680

 
6,726

% of average
103
%
 
87
%
 
83
%
Medford, OR
 
 
 
 
 
Actual
4,254

 
3,637

 
3,534

Historical average
4,305

 
4,325

 
4,461

% of average
99
%
 
84
%
 
79
%
(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). During 2017, we modified the calculation for historical average heating degree days. We have recalculated 2016 and 2015 using the updated methodology to be consistent with 2017.

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AVISTA CORPORATION



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, 2017. AEL&P owns four of these generation facilities (totaling 24.5 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78.2 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. AIDEA issued revenue bonds in 1998 (which were refinanced in 2015) to finance its acquisition of the project. These bonds were outstanding in the amount of $59.7 million at December 31, 2017 and mature in January 2034. 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. AIDEA's bonds are payable solely out of the revenues received under the PPA.
For accounting purposes, this PPA is treated as a capital lease and, as of December 31, 2017, the capital lease obligation was $59.7 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for a price equal to 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, 2017, AEL&P also had 107.5 MW of diesel generating capacity from four 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:
chart-1d1b42779a9c5499b1e.jpg
(1)
Normal hydroelectric generation is defined as the energy output of the plant during a year with average inflows to the reservoir.
As of December 31, 2017, 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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AVISTA CORPORATION



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. See "Item 7. Management's Discussion and Analysis – Regulatory Matters" for further discussion of AEL&P's latest general rate case filing, including its capital structure.
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 August 2018, but AEL&P is in the process of renewing and expects the renewed license to be effective in September 2018. Since AEL&P has no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction, other than the reporting and other requirements of the Public Utility Holding Company Act of 2005 as an Avista Corp. subsidiary.
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.
AEL&P ELECTRIC OPERATING STATISTICS
 
 
Years Ended December 31,
 
2017
 
2016
 
2015
ELECTRIC OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
20,504

 
$
18,207

 
$
18,017

Commercial and government
31,726

 
27,322

 
26,049

Public street and highway lighting
279

 
266

 
215

Total retail
52,509

 
45,795

 
44,281

Other
518

 
481

 
497

Total electric operating revenues
$
53,027

 
$
46,276

 
$
44,778

ENERGY SALES (Thousands of MWhs):
 
 
 
 
 
Residential
151

 
139

 
139

Commercial and government
262

 
253

 
258

Public street and highway lighting
1

 
1

 
1

Total electric energy sales
414

 
393

 
398

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
14,575

 
14,448

 
14,285

Commercial and government
2,210

 
2,181

 
2,179

Public street and highway lighting
217

 
211

 
210

Total electric retail customers
17,002

 
16,840

 
16,674

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (KWh)
10,360

 
9,621

 
9,730

Revenue per KWh (in cents)
13.58

 
13.10

 
12.96

Annual revenue per customer
$
1,406.79

 
$
1,260.17

 
$
1,261.25

HEATING DEGREE DAYS: (1)
 
 
 
 
 
Juneau, AK
 
 
 
 
 
Actual
8,515

 
7,301

 
7,395

Historical average
8,351

 
8,351

 
8,351

% of average
102
%
 
87
%
 
89
%

(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 heating degree days below historical average indicate warmer than average temperatures).

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AVISTA CORPORATION



OTHER BUSINESSES
The following table shows our assets related to our other businesses, including intercompany amounts as of December 31, 2017 and 2016 (dollars in thousands):
Entity and Asset Type
 
2017
 
2016
Avista Capital
 
 
 
 
Salix - wholly-owned subsidiary
 
$
4,392

 
$
3,842

Equity investments
 
2,561

 
3,000

Other assets
 
2,826

 
123

Avista Development
 
 
 
 
Equity investments
 
19,573

 
11,530

Real estate
 
17,102

 
11,359

Notes receivable and other assets
 
6,385

 
5,444

METALfx - wholly-owned subsidiary
 
11,599

 
11,568

Alaska companies (AERC and AJT Mining)
 
8,803

 
8,390

Total
 
$
73,241

 
$
55,256

Avista Capital
Salix is a wholly-owned subsidiary of Avista Capital that explores markets that could be served with LNG.
Equity investments are primarily in an emerging technology venture capital fund.
Avista Development
Equity investments are primarily in emerging technology venture capital funds and companies, including an investment in a technology company that delivers scalable smart grid solutions to global partners and customers, and a predictive data science company.
Real estate consists primarily of mixed use commercial and retail office space.
Notes receivable and other assets are primarily long-term notes receivable made to a company focused on spurring economic development throughout Washington State and to a smart grid solutions company.
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. The asset balance above excludes an intercompany loan from METALfx to Avista Corp. The loan balance was $5.6 million as of December 31, 2017 and $4.0 million as of December 31, 2016.
Alaska companies
Includes AERC and AJT Mining, which is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain real estate.
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.
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.

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AVISTA CORPORATION



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 our retail operating revenues. The revenue and earnings impact of weather fluctuations is somewhat mitigated by our decoupling mechanisms; however, we could experience liquidity constraints during the period between when decoupling revenue is earned and when it is subsequently collected from customers through retail rates.
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 the Pacific Northwest, even though there may be less extreme weather conditions in the Pacific Northwest.
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 is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in the Pacific Northwest 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

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AVISTA CORPORATION



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 2021. Our subsidiary AEL&P has a $25.0 million committed line of credit 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.
Any default on the lines of credit or other financing arrangements of Avista Corp. or any of our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such 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 swap derivatives 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 derivatives, which can be significant. As of December 31, 2017, we had a net interest rate swap derivative liability of $66.0 million, reflecting a decline in interest rates since the time we entered into the agreements. We did not have any U.S. Treasury lock agreements outstanding as of December 31, 2017. 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 swap 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.
In our 2017 Washington electric and natural gas general rate cases, WUTC Staff recommended the exclusion of our 2016 settled interest rate swaps from the cost of capital calculation. The total amount of the 2016 settled interest rate swaps was $54.0 million, with approximately 60 percent of this total being allocated to Washington. If recovery of the 2016 settled interest rate swap payments referenced above is not approved by the WUTC, this could change our current conclusion that settlement payments related to the 2017 settled interest rate swaps and the unsettled interest rate swaps are probable of recovery through rates. See "Item 7. Management's Discussion and Analysis – Regulatory Matters – 2017 Washington General Rate Cases" for further discussion of this issue.
Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us 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.

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AVISTA CORPORATION



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.
Avista Utilities' annual operating expenses and the costs associated with incremental investments in utility assets continue to grow at a faster rate than revenue growth. 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 do not grant rate increases or 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. Negative impacts to our financial results may result in our credit ratings being downgraded which may make it more costly for us to issue future debt securities and could increase borrowing costs under our credit facilities. See further discussion of regulatory matters in "Item 7. Management's Discussion and Analysis – Regulatory Matters."
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" and "Item 7. Management's Discussion and Analysis – Regulatory Matters – 2017 Washington General Rate Cases."
Energy Commodity Risk Factors
Energy commodity price changes affect our cash flows and results of operations.
Energy commodity prices can be volatile. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. A combination of factors exposes our operations to commodity price risks, including:
our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and 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.
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 income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery

23


AVISTA CORPORATION



through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, 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.
Even if our regulators ultimately allow us to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.
Fluctuating energy commodity prices and volumes in relation to our energy risk management process 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 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 our 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 or be prematurely retired through regulatory action. This could result in higher commodity costs 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, earthquakes, snow and ice storms, which can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies support services and general business operations,
blackouts or disruptions of interconnected transmission systems (the regional power grid),
unplanned outages at generating plants,
fuel cost and availability, including delivery constraints,
explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems,
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,
terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and
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.
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.

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AVISTA CORPORATION



Damage to facilities may be caused by severe weather or natural disasters, such as snow, ice, wind storms, wildfires, earthquakes 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 long-term climate change, both globally and within our utilities' service areas, may affect our operations and financial performance.
Legislative, regulatory and advocacy efforts at the state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric and natural gas utility industries are frequently affected by proposals to curb greenhouse gas and other air emissions. Various regulatory and legislative proposals have been made to limit or further restrict byproducts of combustion, including that resulting from the use of natural gas by our customers. In addition, regionally, there are a number of regulatory and legislative initiatives that have been proposed which could introduce carbon pricing or cap-and-trade mechanisms related to greenhouse gas emissions, and we cannot predict whether any such proposals will be enacted. Such proposals, if adopted, could restrict the operation and raise the costs of our power generation resources as well as the distribution of natural gas to our customers.
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,
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,
require construction of specific types of generation plants at higher cost, and
increase the cost of distributing natural gas to customers.
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.

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AVISTA CORPORATION



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. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees.
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 use of technology systems could result in the unavailability of such systems, and 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 and/or employee information or other proprietary data that could adversely affect our reputation and competitiveness, could result in costly litigation and negatively impact our results of operations. These cyber attacks have become more common and sophisticated and, as such, 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 planning to replace all of our electric meter infrastructure in Washington State with two-way communication advanced metering infrastructure (AMI). There is the risk that regulators will not allow the full recovery of new AMI. 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. Finally, there is the risk that we ultimately do not complete the project and will incur contract cancellation or other costs, which could be significant.
Strategic Risk Factors
Our strategic business plans, which may be affected by any or all of the foregoing, may change, 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,
market or other conditions may adversely affect our operations or require changes to our business strategy, which could result in a non-cash goodwill impairment charge that would reduce assets and reduce our net income, and
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.
We are subject to various risks specifically related to the proposed acquisition by Hydro One.
The conditions to the acquisition may not be satisfied.
The proposed acquisition by Hydro One requires approval by the holders of a majority of Avista Corp.'s outstanding shares of common stock and the receipt of regulatory approvals, including from the FERC, the Committee on Foreign Investment in the United States (CFIUS), the Federal Communications Commission (FCC), the WUTC, IPUC, MPSC, OPUC, and the RCA. Also, the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended is required. Avista Corp. shareholder and FERC approval have been obtained; however, the other regulatory approvals may not be obtained or the regulatory bodies may seek to impose conditions on the completion of the transaction, which could cause the conditions specified in the Merger Agreement to not be satisfied or which could delay or increase the

26


AVISTA CORPORATION



cost of the transaction. In addition, the failure to satisfy other closing conditions could result in a termination of the Merger Agreement by Hydro One and/or Avista Corp.
We may be required to pay a termination fee if the acquisition is not consummated.
Upon termination of the Merger Agreement under certain specified circumstances, we would be required to pay Hydro One a termination fee of $103.0 million (Company Termination Fee). We would also be required to pay Hydro One the Company Termination Fee in the event that we signed or consummated any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. Any fees due as a result of termination could have a material adverse effect on our results of operations, financial condition, and cash flows.
Failure to consummate the acquisition could negatively impact the market value of Avista Corp. common stock and our access to and cost of capital.
There can be no assurance that the Merger will be consummated. Failure to consummate the Merger could (i) affect the value of Avista Corp.'s common stock, including by reducing it to a level at or below the trading range preceding the announcement of the Merger Agreement and (ii) negatively affect our access to and cost of both equity and debt financing.
Additionally, if the Merger is not consummated, we would have incurred significant costs and diverted the time and attention of management. A failure to consummate the Merger might also result in negative publicity, litigation against Avista Corp. or its directors and officers, and a negative impression of Avista Corp. in the financial markets. The occurrence of any of these events individually or in combination could have a material adverse effect on our financial condition, results of operations, cash flows and stock price.
We have been faced with legal proceedings related to the pending acquisition by Hydro One.
In connection with the proposed acquisition, as of the date of this annual report, three lawsuits have been filed in the United States District Court for the Eastern District of Washington and one lawsuit has been filed in the Superior Court for the State of Washington in and for Spokane County. These lawsuits were filed against members of the Company's Board of Directors and various other parties. The three lawsuits filed in the United States District Court for the Eastern District of Washington have been voluntarily dismissed by the plaintiffs, leaving only the state lawsuit remaining.
The remaining complaint generally alleges that the members of the Board breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalues Avista Corp., and that Hydro One, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported breaches of duty. The aiding and abetting claims were brought only against Hydro One, Olympus Holding Corp. and Olympus Corp. The complaints seek various remedies, including an injunction against the acquisition and monetary damages, including attorneys’ fees and expenses. The complaint has been stayed by the court until the closing of the transaction at which time the plaintiff will have the option to file an amended complaint within 30 days of such closing. If the amended complaint is not filed within the 30 days the suit will be dismissed.
Since Avista Corp. is obligated to indemnify the defendants under its articles of incorporation, bylaws and separate agreements, the outcome of the lawsuit could, among other things, result in a material adverse effect on Avista Corp.'s financial condition, results of operations 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.
Recent U.S. tax legislation may materially adversely affect our financial condition, results of operations and cash flows and affect our credit ratings.
On December 22, 2017, the "Tax Cuts and Jobs Act" (TCJA) was signed into law. The legislation includes substantial changes to the taxation of individuals as well as U.S. businesses, multi-national enterprises, and other types of taxpayers. The most significant change as a result of the TCJA is a permanent reduction of the statutory corporate tax rate from 35 percent to 21 percent. The legislation is unclear in certain respects and will require implementing regulations by the U.S. Treasury Department, as well as interpretations by the Internal Revenue Service (IRS) and state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the legislation. In addition, the regulatory treatment of certain impacts of this legislation will be subject to the discretion of the FERC and state public utility commissions.
Our analysis and interpretation of this legislation is complete as it relates to amounts recorded as of December 31, 2017 and based on our evaluation, the reduction of the U.S. corporate income tax rate required a write-down of our deferred income tax

27


AVISTA CORPORATION



assets and liabilities (including the value of our net operating loss carryforwards) during the fourth quarter of 2017, the period in which the tax legislation was enacted. Because we are predominantly a rate-regulated entity, a large portion of the net effect of the legislation has been recorded as a net regulatory liability on the Consolidated Balance Sheets that will be returned to customers through the ratemaking process in future periods.
Although it is unclear when or how capital markets, credit rating agencies, the FERC or state public utility commissions may respond to this legislation, we do expect that certain financial metrics used by credit rating agencies to evaluate the Company may be negatively impacted as a result of the TCJA. This is primarily due to our expectation that future cash flows from operations will be negatively impacted due to the loss of the bonus depreciation tax deduction and from the timing of the return of excess deferred taxes to customers. There may be other material adverse effects resulting from the legislation that we have not yet identified. Moody's has placed a negative outlook on our credit rating. We cannot predict whether Moody's will take further action in the future, or whether other credit rating agencies will take similar action. Any further action by credit rating agencies may make it more costly for us to issue future debt securities and could increase borrowing costs under our credit facilities.
We believe that interpretations and implementing regulations by the IRS, as well as potential amendments and technical corrections, could result in reducing the negative impacts of certain aspects of this legislation, although there can be no assurance that this will occur or that interpretations, regulations, amendments and technical corrections will not exacerbate some of the negative impacts of the legislation. If additional interpretations, regulations, amendments or technical corrections and/or actions by the FERC and state public utility commissions exacerbate the adverse impacts of the legislation, the legislation could have a material adverse effect on our financial condition, results of operations and cash flows.
See "Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" and "Forward-Looking Statements" for discussion of or reference to additional 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.

28


AVISTA CORPORATION



ITEM 2. PROPERTIES
AVISTA UTILITIES
Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s mortgage indenture.
Avista Utilities' 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
 
40.4

 
40.4

Nine Mile (Spokane)
4
 
37.6

 
37.6

Upper Falls (Spokane)
1
 
10.0

 
10.2

Monroe Street (Spokane)
1
 
14.8

 
15.0

Idaho:
 
 
 
 
 
Cabinet Gorge (Clark Fork) (3)
4
 
265.0

 
273.0

Post Falls (Spokane)
6
 
14.8

 
15.4

Montana:
 
 
 
 
 
Noxon Rapids (Clark Fork)
5
 
487.8

 
562.4

Total Hydroelectric
 
 
940.4

 
1,042.0

Thermal Generating Stations (cycle, fuel source)
 
 
 
 
 
Washington:
 
 
 
 
 
Kettle Falls GS (combined-cycle, wood waste) (4)
1
 
50.7

 
53.5

Kettle Falls CT (combined-cycle, natural gas) (4)
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

 
24.6

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

 
166.5

Montana:
 
 
 
 
 
Colstrip Units 3 & 4 (simple-cycle, coal) (5)
2
 
233.4

 
222.0

Oregon:
 
 
 
 
 
Coyote Springs 2 (combined-cycle, natural gas)
1
 
295.0

 
295.0

Total Thermal
 
 
839.2

 
833.3

Total Generation Properties
 
 
1,779.6

 
1,875.3


(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, 2017.
(3)
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.
(4)
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.
(5)
Jointly owned; data refers to our 15 percent interest.

29


AVISTA CORPORATION



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 approximately 700 miles of 230 kV line and approximately 1,550 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 GS 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 2,400 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 15 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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AVISTA CORPORATION



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

 
51.8

Auke Bay
3
 
28.4

 
25.2

Gold Creek
5
 
8.2

 
7

Industrial Blvd. Plant
1
 
23.5

 
23.5

Total Diesel
 
 
121.5

 
107.5

Total Generation Properties
 
 
228.1

 
210.2

(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, 2017.
(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 are 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, 2018, there were 7,848 registered shareholders of our common stock.
Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a recurring 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.

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AVISTA CORPORATION



Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).
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 - 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 in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC,
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), and
the Merger Agreement with Hydro One, which states Avista Corp. cannot (A) declare, authorize, set aside for payment or pay any dividend on, or make any other distribution in respect of, any shares of its capital stock, other than (1) dividends paid by any Subsidiary of the Company to the Company or to any wholly owned subsidiary of the Company, (2) quarterly cash dividends with respect to the Company common stock not to exceed the 2017 annual per share dividend rate by more than $0.06 per year, with record dates and payment dates consistent with the Company’s current dividend practice, or (3) a “stub period” dividend to holders of record of Company common stock as of immediately prior to the effective time of the merger equal to the product of (x) the number of days from the record date for payment of the last quarterly dividend paid by the Company prior to the effective time of the merger, multiplied by (y) a daily dividend rate determined by dividing the amount of the last quarterly dividend prior to the effective time of the merger by ninety-one or (B) adjust, split, combine, subdivide or reclassify any shares of its capital stock (see "Note 4 of the Notes to Consolidated Financial Statements" for additional information regarding the merger).
On February 2, 2018, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3725 per share on the Company’s common stock. This was an increase of $0.015 per share, or 4.2 percent from the previous quarterly dividend of $0.3575 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
2017
 
 
 
 
 
 
 
Dividends paid per common share
$
0.3575

 
$
0.3575

 
$
0.3575

 
$
0.3575

Trading price range per common share:
 
 
 
 
 
 
 
High
$
40.14

 
$
44.40

 
$
52.74

 
$
52.35

Low
$
37.94

 
$
38.62

 
$
41.35

 
$
51.25

2016
 
 
 
 
 
 
 
Dividends paid per common share
$
0.3425

 
$
0.3425

 
$
0.3425

 
$
0.3425

Trading price range per common share:
 
 
 
 
 
 
 
High
$
41.12

 
$
44.80

 
$
44.97

 
$
42.63

Low
$
34.67

 
$
38.70

 
$
40.43

 
$
39.11

On July 18, 2017, the last trading day prior to the public announcement of the Merger Agreement with Hydro One, the reported last sale price for Avista Corp. common stock was $42.74 per share as reported in the consolidated reporting system. On July 20, 2017, the first trading day following the announcement of the Merger Agreement, the reported last sale price for Avista Corp. common stock was $52.28 per share as reported in the consolidated reporting system.

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AVISTA CORPORATION



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.”
ITEM 6. SELECTED FINANCIAL DATA
 
(in thousands, except per share data and ratios)
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Operating Revenues:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
1,370,359

 
$
1,372,638

 
$
1,411,863

 
$
1,413,499

 
$
1,403,995

AEL&P
53,027

 
46,276

 
44,778

 
21,644

 

Other
22,543

 
23,569

 
28,685

 
39,219

 
39,549

Intersegment eliminations

 

 
(550
)
 
(1,800
)
 
(1,800
)
Total
$
1,445,929

 
$
1,442,483

 
$
1,484,776

 
$
1,472,562

 
$
1,441,744

Income (Loss) from Operations (pre-tax):
Avista Utilities
$
270,409

 
$
277,070

 
$
241,228

 
$
239,976

 
$
232,572

AEL&P
17,947

 
15,434

 
14,072

 
6,221

 

Other
(3,847
)
 
(2,701
)
 
(2,086
)
 
6,391

 
(1,483
)
Total
$
284,509

 
$
289,803

 
$
253,214

 
$
252,588

 
$
231,089

Net income from continuing operations
$
115,932

 
$
137,316

 
$
118,170

 
$
119,866

 
$
104,333

Net income from discontinued operations

 

 
5,147

 
72,411

 
7,961

Net income
$
115,932

 
$
137,316

 
$
123,317

 
$
192,277

 
$
112,294

Net income attributable to noncontrolling interests
$
(16
)
 
$
(88
)
 
$
(90
)
 
$
(236
)
 
$
(1,217
)
Net Income (Loss) attributable to Avista Corporation shareholders:
Avista Utilities
$
114,716

 
$
132,490

 
$
113,360

 
$
113,263

 
$
108,598

AEL&P
9,054

 
7,968

 
6,641

 
3,152

 

Ecova - Discontinued operations

 

 
5,147

 
72,390

 
7,129

Other
(7,854
)
 
(3,230
)
 
(1,921
)
 
3,236

 
(4,650
)
Net income attributable to Avista Corp. shareholders
$
115,916

 
$
137,228

 
$
123,227

 
$
192,041

 
$
111,077

Average common shares outstanding, basic
64,496

 
63,508

 
62,301

 
61,632

 
59,960

Average common shares outstanding, diluted
64,806

 
63,920

 
62,708

 
61,887

 
59,997

Common shares outstanding at year-end
65,494

 
64,188

 
62,313

 
62,243

 
60,077

Earnings per common share attributable to Avista Corp. shareholders, basic:
Earnings per common share from continuing operations
$
1.80

 
$
2.16

 
$
1.90

 
$
1.94

 
$
1.74

Earnings per common share from discontinued operations

 

 
0.08

 
1.18

 
0.11

Total earnings per common share attributable to Avista Corp. shareholders, basic
$
1.80

 
$
2.16

 
$
1.98

 
$
3.12

 
$
1.85

Earnings per common share attributable to Avista Corp. shareholders, diluted:
Earnings per common share from continuing operations
$
1.79

 
$
2.15

 
$
1.89

 
$
1.93

 
$
1.74

Earnings per common share from discontinued operations

 

 
0.08

 
1.17

 
0.11

Total earnings per common share attributable to Avista Corp. shareholders, diluted
$
1.79

 
$
2.15

 
$
1.97

 
$
3.10

 
$
1.85

 
 
 
 
 
 
 
 
 
 

33


AVISTA CORPORATION



(in thousands, except per share data and ratios)
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Dividends declared per common share
$
1.43

 
$
1.37

 
$
1.32

 
$
1.27

 
$
1.22

Book value per common share
$
26.41

 
$
25.69

 
$
24.53

 
$
23.84

 
$
21.61

Total Assets at Year-End:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
5,177,878

 
$
4,975,555

 
$
4,601,708

 
$
4,357,760

 
$
3,930,251

AEL&P
278,688

 
273,770

 
265,735

 
263,070

 

Other
73,241

 
60,430

 
39,206

 
80,141

 
81,282

Total (1)
$
5,529,807

 
$
5,309,755

 
$
4,906,649

 
$
4,700,971

 
$
4,011,533

Long-Term Debt and Capital Leases (including current portion)
$
1,769,237

 
$
1,682,004

 
$
1,573,278

 
$
1,487,126

 
$
1,262,036

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

 
$

 
$

 
$
1,431

 
$
17,838

Long-Term Debt to Affiliated Trusts
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

Total Avista Corp. Shareholders’ Equity
$
1,729,828

 
$
1,648,727

 
$
1,528,626

 
$
1,483,671

 
$
1,298,266

Ratio of Earnings to Fixed Charges (2)
2.95

 
3.32

 
3.13

 
3.39