Edgar Filing: AVISTA CORP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________________________________________

Form 10-Q

(Mark One)



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

FOR THE QUARTERLY PERIOD ENDED March 31, 2018 OR



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

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-3701

__________________________________________________________________________________________

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)



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

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

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

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

None

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes x No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.



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

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 ¨

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

As of April 30, 2018, 65,669,485 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

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AVISTA CORPORATION

INDEX



Item No.		Page No.

	Forward-Looking Statements	1
	Available Information	4
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Income - Three Months Ended March 31, 2018 and 2017	5
	Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2018 and 2017	6
	Condensed Consolidated Balance Sheets - March 31, 2018 and December 31, 2017	7
	Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2018 and 2017	9
	Condensed Consolidated Statements of Equity - Three Months Ended March 31, 2018 and 2017	11
	Notes to Condensed Consolidated Financial Statements	12
	Note 1. Summary of Significant Accounting Policies	12
	Note 2. New Accounting Standards	14
	Note 3. Revenue	16
	Note 4. Derivatives and Risk Management	20
	Note 5. Pension Plans and Other Postretirement Benefit Plans	24
	Note 6. Committed Lines of Credit	25
	Note 7. Long-Term Debt to Affiliated Trusts	25
	Note 8. Fair Value	26
	Note 9. Common Stock	30
	Note 10. Earnings per Common Share Attributable to Avista Corporation Shareholders	30
	Note 11. Commitments and Contingencies	30
	Note 12. Information by Business Segments	32
	Note 13. Pending Acquisition by Hydro One	33
	Report of Independent Registered Public Accounting Firm	36

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Business Segments	37
	Executive Level Summary	37
	Regulatory Matters	38
	Results of Operations - Overall	42
	Non-GAAP Financial Measures	43
	Results of Operations - Avista Utilities	43
	Results of Operations - Alaska Electric Light and Power Company	49
	Results of Operations - Other Businesses	49
	Critical Accounting Policies and Estimates	50
	Liquidity and Capital Resources	50
	Overall Liquidity	50
	Review of Cash Flow Statement	50
	Capital Resources	51
	Capital Expenditures	52
	Off-Balance Sheet Arrangements	52
	Pension Plan	52
	Contractual Obligations	52

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	Environmental Issues and Other Contingencies	52
	Enterprise Risk Management	52

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	54

Item 4.	Controls and Procedures	54

Part II. Other Information
Item 1.	Legal Proceedings	54

Item 1A.	Risk Factors	54

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54

Item 4.	Mine Safety Disclosures	55

Item 6.	Exhibits	55

	Signature	56

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AVISTA CORPORATION

Forward-Looking Statements

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


•	financial performance;


•	cash flows;


•	capital expenditures;


•	dividends;


•	capital structure;


•	other financial items;


•	strategic goals and objectives;


•	business environment; and


•	plans for operations.

These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), 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 Quarterly Report on Form 10-Q) 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, 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, conservation measures and/or increased distributed generation;


•	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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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 or lawsuits 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 containers 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 other 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 cost of replacement power (diesel);


•	changing river regulation or operations 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;

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;

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AVISTA CORPORATION


•	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;


•	entering into or growth of 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 Tax Cuts and Jobs Act 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, healthcare regulations and import/export 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 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

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AVISTA CORPORATION

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.

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PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands, except per share amounts

(Unaudited)



	2018			2017
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	408,356		$	445,573
Alternative revenue programs	(5,939		)	(15,036		)
Total utility revenues	402,417			430,537
Non-utility revenues	6,944			5,933
Total operating revenues	409,361			436,470
Operating Expenses:
Utility operating expenses:
Resource costs	154,618			165,586
Other operating expenses	77,298			72,443
Acquisition costs	672			—
Depreciation and amortization	44,733			41,985
Taxes other than income taxes	30,829			32,662
Non-utility operating expenses:
Other operating expenses	6,824			6,179
Depreciation and amortization	181			188
Total operating expenses	315,155			319,043
Income from operations	94,206			117,427
Interest expense	24,776			23,545
Interest expense to affiliated trusts	253			185
Capitalized interest	(968		)	(724		)
Other expense (income)-net	4,479			(1,060		)
Income before income taxes	65,666			95,481
Income tax expense	10,710			33,344
Net income	54,956			62,137
Net income attributable to noncontrolling interests	(66		)	(21		)
Net income attributable to Avista Corp. shareholders	$	54,890		$	62,116
Weighted-average common shares outstanding (thousands), basic	65,639			64,362
Weighted-average common shares outstanding (thousands), diluted	65,931			64,469

Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	0.84		$	0.97
Diluted	$	0.83		$	0.96
Dividends declared per common share	$	0.3725		$	0.3575

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)



	2018			2017
Net income	$	54,956		$	62,137
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $55 and $98 respectively	204			183
Total other comprehensive income	204			183
Comprehensive income	55,160			62,320
Comprehensive income attributable to noncontrolling interests	(66		)	(21		)
Comprehensive income attributable to Avista Corporation shareholders	$	55,094		$	62,299

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)



	March 31,		December 31,
	2018		2017
Assets:
Current Assets:
Cash and cash equivalents	$	26,273	$	16,172
Accounts and notes receivable-less allowances of $6,077 and $5,132, respectively	168,534		185,664
Regulatory asset for energy commodity derivatives	21,073		24,991
Materials and supplies, fuel stock and stored natural gas	49,259		58,075
Other current assets	44,608		52,632
Total current assets	309,747		337,534
Net Utility Property:
Utility plant in service	5,882,288		5,853,308
Construction work in progress	165,113		157,839
Total	6,047,401		6,011,147
Less: Accumulated depreciation and amortization	1,629,164		1,612,337
Total net utility property	4,418,237		4,398,810
Other Non-current Assets:
Investment in affiliated trusts	11,547		11,547
Goodwill	57,672		57,672
Other property and investments-net and other non-current assets	91,536		83,912
Total other non-current assets	160,755		153,131
Deferred Charges:
Regulatory assets for deferred income tax	90,519		90,315
Regulatory assets for pensions and other postretirement benefits	206,637		209,115
Other regulatory assets	128,813		127,328
Regulatory asset for interest rate swaps	151,667		169,704
Non-current regulatory asset for energy commodity derivatives	9,094		18,967
Other deferred charges	9,714		9,828
Total deferred charges	596,444		625,257
Total assets	$	5,485,183	$	5,514,732

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands

(Unaudited)



	March 31,			December 31,
	2018			2017
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	67,168		$	107,289
Current portion of long-term debt and capital leases	275,066			277,438
Short-term borrowings	50,000			105,398
Energy commodity derivative liabilities	9,760			8,848
Income taxes payable	15,845			413
Accrued interest	30,189			16,351
Accrued taxes other than income taxes	45,102			33,802
Deferred natural gas costs	31,148			37,474
Current portion of pensions and other postretirement benefits	10,907			11,544
Current unsettled interest rate swap derivative liabilities	25,086			34,447
Current regulatory liability for excess deferred income taxes	26,242			—
Other current liabilities	83,184			64,498
Total current liabilities	669,697			697,502
Long-term debt and capital leases	1,491,395			1,491,799
Long-term debt to affiliated trusts	51,547			51,547
Regulatory liability for utility plant retirement costs	288,019			285,786
Pensions and other postretirement benefits	200,162			203,566
Deferred income taxes	464,596			466,630
Regulatory liability for excess deferred income taxes	413,491			442,319
Other non-current liabilities, regulatory liabilities and deferred credits	147,705			145,099
Total liabilities	3,726,612			3,784,248
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)

Equity:
Avista Corporation Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 65,668,477 and 65,494,333 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively	1,131,549			1,133,448
Accumulated other comprehensive loss	(9,628		)	(8,090		)
Retained earnings	636,468			604,470
Total Avista Corporation shareholders’ equity	1,758,389			1,729,828
Noncontrolling Interests	182			656
Total equity	1,758,571			1,730,484
Total liabilities and equity	$	5,485,183		$	5,514,732

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)



	2018			2017
Operating Activities:
Net income	$	54,956		$	62,137
Non-cash items included in net income:
Depreciation and amortization	45,823			43,084
Deferred income tax provision (benefit) and investment tax credits	(5,049		)	17,614
Power and natural gas cost amortizations, net	72			3,091
Amortization of debt expense	815			813
Amortization of investment in exchange power	613			613
Stock-based compensation expense	1,963			832
Equity-related Allowance for Funds Used During Construction (AFUDC)	(1,392		)	(1,650		)
Pension and other postretirement benefit expense	8,170			9,348
Other regulatory assets and liabilities and deferred debits and credits	2,127			(6,878		)
Change in decoupling regulatory deferral	5,703			14,857
Other	3,778			(116		)
Contributions to defined benefit pension plan	(7,300		)	(7,400		)
Changes in certain current assets and liabilities:
Accounts and notes receivable	15,963			(668		)
Materials and supplies, fuel stock and stored natural gas	8,815			6,129
Collateral posted for derivative instruments	18,382			(2,620		)
Income taxes receivable	314			14,106
Other current assets	(787		)	(116		)
Accounts payable	(21,997		)	(20,239		)
Income taxes payable	15,432			—
Other current liabilities	38,374			16,778
Net cash provided by operating activities	184,775			149,715

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(81,817		)	(86,763		)
Issuance of notes receivable at subsidiaries	(1,000		)	(400		)
Equity and property investments made by subsidiaries	(3,671		)	(2,627		)
Other	(866		)	(137		)
Net cash used in investing activities	(87,354		)	(89,927		)

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)



	2018			2017
Financing Activities:
Net decrease in short-term borrowings	$	(55,398	)	$	(15,000	)
Maturity of long-term debt and capital leases	(3,037		)	(822		)
Issuance of common stock, net of issuance costs	232			315
Cash dividends paid	(24,634		)	(23,167		)
Other	(4,483		)	(3,442		)
Net cash used in financing activities	(87,320		)	(42,116		)

Net increase in cash and cash equivalents	10,101			17,672

Cash and cash equivalents at beginning of period	16,172			8,507

Cash and cash equivalents at end of period	$	26,273		$	26,179

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)



	2018			2017
Common Stock, Shares:
Shares outstanding at beginning of period	65,494,333			64,187,934
Shares issued	174,144			198,218
Shares outstanding at end of period	65,668,477			64,386,152
Common Stock, Amount:
Balance at beginning of period	$	1,133,448		$	1,075,281
Equity compensation expense	1,798			922
Issuance of common stock, net of issuance costs	232			315
Payment of minimum tax withholdings for share-based payment awards	(3,929		)	(3,420		)
Balance at end of period	1,131,549			1,073,098
Accumulated Other Comprehensive Loss:
Balance at beginning of period	(8,090		)	(7,568		)
Other comprehensive income	204			183
Reclassification of excess income tax benefits	(1,742		)	—
Balance at end of period	(9,628		)	(7,385		)
Retained Earnings:
Balance at beginning of period	604,470			581,014
Net income attributable to Avista Corporation shareholders	54,890			62,116
Cash dividends paid on common stock	(24,634		)	(23,167		)
Reclassification of excess income tax benefits	1,742			—
Balance at end of period	636,468			619,963
Total Avista Corporation shareholders’ equity	1,758,389			1,685,676
Noncontrolling Interests:
Balance at beginning of period	656			(251		)
Net income attributable to noncontrolling interests	66			21
Cash dividends paid to subsidiary noncontrolling interests	(540		)	—
Balance at end of period	182			(230		)
Total equity	$	1,758,571		$	1,685,446

The Accompanying Notes are an Integral Part of These Statements.

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AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corporation (Avista Corp. or the Company) as of and for the interim periods ended March 31, 2018 and March 31, 2017 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 (2017 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2017 Form 10-K for definitions of certain terms not defined herein. The acronyms and terms are an integral part of these condensed consolidated financial statements.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is 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.

Alaska Energy and Resources Company (AERC) is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is Alaska Electric Light and Power Company (AEL&P), which comprises Avista Corp.'s regulated utility operations in Alaska.

Avista Capital, Inc. (Avista Capital), a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 12 for business segment information.

On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One Limited (Hydro One). Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 13 for additional information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31,		December 31,
	2018		2017
Materials and supplies	$	43,202	$	41,493
Fuel stock	4,798		4,843
Stored natural gas	1,259		11,739
Total	$	49,259	$	58,075

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Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value.

The Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC) issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets have been concluded to be probable of recovery through future rates.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.

For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 8 for the Company’s fair value disclosures.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31,		December 31,
	2018		2017
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,559 and $4,356, respectively (a)	$	9,628	$	8,090


(a)	Effective January 1, 2018, the Company adopted ASU No. 2018-02. As a result of the adoption of this new standard, $1.7 million in excess tax benefits was reclassified from accumulated other comprehensive loss to retained earnings. See Note 2 for additional discussion of the adoption of this standard.

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The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three months ended March 31 (dollars in thousands).



	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components	2018			2017			Affected Line Item in Statement of Income
Amortization of defined benefit pension items
Amortization of net prior service cost	$	(228	)	$	(299	)	(a)
Amortization of net loss	2,995			3,638			(a)
Adjustment due to effects of regulation	(2,508		)	(3,058		)	(a)
	259			281			Total before tax
	(55		)	(98		)	Tax expense
	$	204		$	183		Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Effective Income Tax Rate

For the three months ended March 31, 2018 and 2017, the Company's effective tax rate was 16.3 percent and 34.9 percent, respectively. The effective tax rate decreased during 2018 due to federal income tax law changes which were enacted during the fourth quarter of 2017, which lowered the federal income tax rate from 35 percent to 21 percent. In addition, there were reductions to the effective tax rate in 2018 due to plant excess deferred income taxes being amortized under the Average Rate Assumption Method (ARAM) and due to excess tax benefits from the settlement of equity awards during the first quarter of 2018.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. As of March 31, 2018, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 11 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”

On January 1, 2018, the Company adopted ASU No. 2014-09, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.

The Company elected to use a modified retrospective method of adoption, which required a cumulative adjustment to opening retained earnings (if any were identified), as opposed to a full retrospective application. The Company did not identify any adjustments required to opening retained earnings related to the adoption of the new revenue standard. The Company applied the retrospective application only to contracts that were not completed as of the implementation date. The Company did not apply the new guidance to contracts that were completed with all revenue recognized prior to the implementation date. In addition, total operating revenues on the Condensed Consolidated Statements of Income in years prior to 2018 would not have changed if the Company had elected to apply the full retrospective method of adoption.

Since the majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers and revenue is recognized as energy is delivered to these customers, the Company does not expect any significant change in operating revenues or net income going forward.

The only changes in revenue that resulted from the adoption of this ASU were related to the presentation of utility-related taxes collected from customers and the timing of when revenue from self-generated renewable energy credits (REC) is recognized.

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Under ASU No. 2014-09, revenue associated with the sale of RECs is recognized at the time of generation and sale of the credits as opposed to when the RECs are certified in the Western Renewable Energy Generation Information System, which generally occurs during a period subsequent to the sale. This represents a change from the Company's prior practice, which was to defer revenue recognition until the time of certification. Revenue associated with the sale of RECs is not material to the financial statements and almost all of the Company's REC revenue is deferred for future rebate to retail customers. As such, the change in the timing of revenue recognition does not have a material impact on net income.

See Note 3 for the Company's complete revenue disclosures.

ASU No. 2016-02 “Leases (Topic 842)”

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-02. This ASU introduces a new lessee model that requires most leases to be capitalized and shown on the balance sheet with corresponding lease assets and liabilities. The standard also aligns certain of the underlying principles of the new lessor model with those in Topic 606, the FASB’s new revenue recognition standard. Furthermore, this ASU addresses other issues that arise under the current lease model; for example, eliminating the required use of bright-line tests in current GAAP for determining lease classification (operating leases versus capital leases). This ASU also includes enhanced disclosures surrounding leases. This ASU is effective for periods beginning on or after December 15, 2018; however, early adoption is permitted. Under ASU No. 2016-02, upon adoption, the effects of this standard must be applied using a modified retrospective approach to the earliest period presented, which will likely require restatements of previously issued financial statements. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. During the first quarter of 2018, a proposed ASU was issued by the FASB that provides a practical expedient that would allow companies to use an optional transition method, which would allow for a cumulative adjustment to retained earnings during the period of adoption and prior periods would not require restatement.

The Company evaluated ASU No. 2016-02 and determined that it will not early adopt this standard before its effective date in 2019.

The Company has formed a lease standard implementation team that is working through the implementation process. Based on work to date, the implementation team has identified a complete population of existing and potential leases under the new standard and has completed its review of the agreements associated with this population. However, the team has not yet quantified the impact of recording these leases. In addition, the team is developing a process to identify any new potential leases that may be entered into prior to the standard implementation date in 2019.

The Company is monitoring utility industry implementation guidance as it relates to several unresolved issues to determine if there will be an industry consensus. The Company has not estimated the potential impact on its future financial condition, results of operations and cash flows.

ASU No. 2017-07 “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”

On January 1, 2018, the Company adopted ASU No. 2017-07, which amended the income statement presentation of the components of net period benefit cost for an entity’s defined benefit pension and other postretirement plans. Under previous GAAP, net benefit cost consisted of several components that reflected different aspects of an employer’s financial arrangements as well as the cost of benefits earned by employees. These components were aggregated and reported net in the financial statements. ASU No. 2017-07 requires entities to (1) disaggregate the current service-cost component from the other components of net benefit cost (other components) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations.

In addition, only the service-cost component of net benefit cost is eligible for capitalization (e.g., as part of utility plant). This is a change from prior practice, under which entities capitalized the aggregate net benefit cost to utility plant when applicable, in accordance with Federal Energy and Regulatory Commission (FERC) accounting guidance. Avista Corp. is a rate-regulated entity and all components of net benefit cost are currently recovered from customers as a component of utility plant and, under the new ASU, these costs will continue to be recovered from customers in the same manner over the depreciable lives of utility plant. As all such costs are expected to continue to be recoverable, the components that are no longer eligible to be recorded as a component of utility plant for GAAP will be recorded as regulatory assets.

Upon adoption, entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement and a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the

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service-cost component. Due to the retrospective requirements for income statement presentation, for the three months ended March 31, 2017, the Company reclassified $2.0 million in non-service cost components of pension and other postretirement benefits from utility other operating expenses to other expense (income)-net on the Condensed Consolidated Statements of Income. See Note 5 for additional discussion regarding pension and other postretirement benefit expense.

ASU No. 2018-02 “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”

In February 2018, the FASB issued ASU No. 2018-02, which amended the guidance for reporting comprehensive income. This ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the Tax Cuts and Jobs Act (TCJA) in December 2017. This ASU is effective for periods beginning after December 15, 2018 and early adoption is permitted. Upon adoption, the requirements of this ASU must be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company early adopted this standard effective January 1, 2018 and elected to apply the guidance during the period of adoption rather than apply the standard retrospectively. As a result, the Company reclassified $1.7 million in tax benefits from accumulated other comprehensive loss to retained earnings during the three months ended March 31, 2018.

NOTE 3. REVENUE

ASC 606, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and superseded previous revenue recognition guidance, including industry-specific guidance, became effective on January 1, 2018. The core principle of the revenue model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

Utility Revenues

Revenue from Contracts with Customers

General

The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy.

In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the Company are conducted subject to the regulator-approved tariff.

Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time.

Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."

Unbilled Revenue from Contracts with Customers

The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month (once per month for each individual customer). At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. The Company's estimate of unbilled revenue is based on:


•	the number of customers,

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•	current rates,


•	meter reading dates,


•	actual native load for electricity,


•	actual throughput for natural gas, and


•	electric line losses and natural gas system losses.

Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs.

Accounts receivable includes unbilled energy revenues of the following amounts as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31,		December 31,
	2018		2017
Unbilled accounts receivable	$	51,835	$	68,641

Non-Derivative Wholesale Contracts

The Company has certain wholesale contracts which do not meet the criteria for classification as derivatives. Since they do not meet the definition of a derivative, they are within the scope of ASC 606 and are considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for specified period of time, consistent with the discussion of tariff sales above.

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Condensed Consolidated Statement of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.

Two acceptable methods of presenting decoupling revenue have evolved within the utility industry and a policy election is required by the Company. The two options relate to how the collection/refund of previously recognized decoupling revenue is presented within total revenue. The first option is the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Condensed Consolidated Statement of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. The second option is the net method, which requires the amortization of the decoupling regulatory asset/liability to be presented within revenue from contracts with customers such that, when netted against the cash passing between the Company and the customers within the same line item, there is a net zero impact to revenue from contracts with customers and total revenue. The Company has elected the gross method for the presentation of alternative revenue program revenue, consistent with historical practice. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically scoped out of ASC 606. As such, these revenues are disclosed separately from

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revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions which are entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, revenues from the lineman training school, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the provision for rate refunds associated with the TCJA, enacted in December 2017. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Other Considerations for Utility Revenues

Contracts with Multiple Performance Obligations

In addition to the tariff sales described above, which are stand-alone energy sales, the Company has bundled arrangements which contain multiple performance obligations including some combination of energy, capacity, energy reserves and RECs. Under these arrangements, the total contract price is allocated to the various performance obligations and revenue is recognized as the obligations are satisfied. Depending on the source of the revenue, it could either be included in revenue from contracts with customers or derivative revenue.

Gross Versus Net Presentation

Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the principal in these transactions and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, AEL&P is acting as the agent in these transactions. As such, effective January 1, 2018, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers. Prior to the adoption of ASU No. 2014-09, the Company presented utility-related taxes at AEL&P on a gross basis, consistent with the presentation for Avista Utilities. In prior years, there were approximately $2.0 million annually in utility-related taxes collected from customers included in revenue for AEL&P.

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three months ended March 31 (dollars in thousands):



	2018		2017
Utility-related taxes	$	19,167	$	21,584

Non-Utility Revenues

Revenue from Contracts with Customers

Non-utility revenues from contracts with customers are primarily derived from the operations of METALfx. The contracts associated with METALfx have one performance obligation, the delivery of a product, and revenues are recognized when the risk of loss transfers to the customer, which occurs when products are shipped.

Other Revenue

Other non-utility revenue primarily relates to rent revenue, which is scoped out of ASC 606; therefore, this revenue is presented separately from revenue from contracts with customers.

Significant Judgments and Unsatisfied Performance Obligations

The vast majority of the Company's revenues are derived from the rate-regulated sale of electricity and natural gas that have two performance obligations that are satisfied throughout the period and as energy is delivered to customers. In addition, the customers do not pay for energy in advance of receiving it. As such, the Company does not have any significant unsatisfied performance obligations or deferred revenues as of period-end associated with these revenues. Also, the only judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers (discussed in detail above) and estimates surrounding the amount of decoupling revenues which will be collected from customers within 24 months.

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The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year and depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer. As of March 31, 2018, the Company estimates it had unsatisfied capacity performance obligations of $13.7 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three months ended March 31 (dollars in thousands):



	2018
Avista Utilities
Revenue from contracts with customers	$	354,162
Derivative revenues	58,392
Alternative revenue programs	(5,939		)
Provision for rate refunds (federal income tax law changes)	(19,822		)
Other utility revenues	1,961
Total Avista Utilities	388,754
AEL&P
Revenue from contracts with customers	14,650
Provision for rate refunds (federal income tax law changes)	(1,122		)
Other utility revenues	135
Total AEL&P	13,663
Other
Revenue from contracts with customers	6,729
Other revenues	215
Total other	6,944
Total operating revenues	$	409,361

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's utility operations for the three months ended March 31 (dollars in thousands):



	2018
	Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	114,753	$	6,538	$	121,291
Commercial and governmental	78,909		8,044		86,953
Industrial	25,119		—		25,119
Public street and highway lighting	1,859		68		1,927
Total retail revenue	220,640		14,650		235,290
Transmission	3,830		—		3,830
Other revenue from contracts with customers	6,291		—		6,291
Total revenue from contracts with customers	$	230,761	$	14,650	$	245,411

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	2018
	Avista Utilities		AEL&P		Total Utility
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	80,653	$	—	$	80,653
Commercial	37,373		—		37,373
Industrial and interruptible	1,683		—		1,683
Total retail revenue	119,709		—		119,709
Transportation	2,567		—		2,567
Other revenue from contracts with customers	1,125		—		1,125
Total revenue from contracts with customers	$	123,401	$	—	$	123,401

NOTE 4. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas 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.

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The following table presents the underlying energy commodity derivative volumes as of March 31, 2018 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
Remainder 2018	246	816	13,783	86,103	162	1,537	7,683	58,035
2019	235	737	610	65,478	94	1,543	1,345	35,438
2020	—	—	910	23,145	—	836	1,430	1,830
2021	—	—	—	—	—	—	1,049	—
2022	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—

The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
2018	426	763	10,572	107,580	213	1,739	3,643	67,375
2019	235	737	610	61,073	94	1,420	1,345	35,438
2020	—	—	910	16,590	—	589	1,430	915
2021	—	—	—	—	—	—	1,049	—
2022	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—


(1)	Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and Purchased Gas Adjustments (PGA)), or in the general rate case process, and are expected to be collected through retail rates from customers.

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within 60 days with U.S. dollars. Avista Corp. hedges foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31,		December 31,
	2018		2017
Number of contracts	23		18
Notional amount (in United States dollars)	$	5,312	$	2,552
Notional amount (in Canadian dollars)	6,866		3,241

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Interest Rate Derivatives

Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, 2018 and December 31, 2017 (dollars in thousands):



Balance Sheet Date	Number of Contracts	Notional Amount		Mandatory Cash Settlement Date
March 31, 2018	14	$	275,000	2018
	6	70,000		2019
	4	40,000		2020
	1	15,000		2021
	5	60,000		2022
December 31, 2017	14	$	275,000	2018
	6	70,000		2019
	3	30,000		2020
	1	15,000		2021
	5	60,000		2022

Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part of Avista Corp.'s cost of debt calculation for ratemaking purposes.

The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates.

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Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, 2018 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	22	$	(6	)	$	—	$	16
Interest rate swap derivatives
Other current assets	3,930		—			—		3,930
Other property and investments-net and other non-current assets	9,512		(358		)	—		9,154
Current unsettled interest rate swap derivative liabilities	1,273		(49,052		)	22,693		(25,086		)
Other non-current liabilities, regulatory liabilities and deferred credits	—		(6,321		)	4,937		(1,384		)
Energy commodity derivatives
Other current assets	995		(34		)	—		961
Current energy commodity derivative liabilities	39,944		(61,978		)	12,274		(9,760		)
Other non-current liabilities, regulatory liabilities and deferred credits	19,133		(28,226		)	4,322		(4,771		)
Total derivative instruments recorded on the balance sheet	$	74,809	$	(145,975	)	$	44,226	$	(26,940	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2017 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	32	$	(1	)	$	—	$	31
Interest rate swap derivatives
Other current assets	2,597		(270		)	—		2,327
Other property and investments-net and other non-current assets	4,880		(2,304		)	—		2,576
Current unsettled interest rate swap derivative liabilities	—		(63,399		)	28,952		(34,447		)
Other non-current liabilities, regulatory liabilities and deferred credits	—		(7,540		)	6,018		(1,522		)
Energy commodity derivatives
Other current assets	1,386		(122		)	—		1,264
Current energy commodity derivative liabilities	26,641		(52,895		)	17,406		(8,848		)
Other non-current liabilities, regulatory liabilities and deferred credits	15,970		(34,936		)	10,032		(8,934		)
Total derivative instruments recorded on the balance sheet	$	51,506	$	(161,467	)	$	62,408	$	(47,553	)

Exposure to Demands for Collateral

Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of

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exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of March 31, 2018 and December 31, 2017 (in thousands):



	March 31,		December 31,
	2018		2017
Energy commodity derivatives
Cash collateral posted	$	28,415	$	39,458
Letters of credit outstanding	28,500		23,000
Balance sheet offsetting (cash collateral against net derivative positions)	16,596		27,438

Interest rate swap derivatives
Cash collateral posted	27,630		34,970
Letters of credit outstanding	3,000		5,000
Balance sheet offsetting (cash collateral against net derivative positions)	27,630		34,970

Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2018 and December 31, 2017 (in thousands):



	March 31,		December 31,
	2018		2017
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	1,376	$	1,336
Additional collateral to post	1,376		1,336

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	55,731		73,514
Additional collateral to post	8,600		18,770

NOTE 5. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ pension and other postretirement plans have not changed during the three months ended March 31, 2018. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $7.3 million in cash to the pension plan for the three months ended March 31, 2018 and expects to contribute a total of $22.0 million in 2018.

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The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three months ended March 31 (dollars in thousands):



	Pension Benefits						Other Postretirement Benefits
	2018			2017			2018			2017
Three months ended March 31:
Service cost (a)	$	5,450		$	5,042		$	804		$	824
Interest cost	6,466			6,951			1,197			1,399
Expected return on plan assets	(8,250		)	(7,900		)	(500		)	(475		)
Amortization of prior service cost	75			—			(815		)	(312		)
Net loss recognition	2,088			2,546			1,655			1,273
Net periodic benefit cost	$	5,829		$	6,639		$	2,341		$	2,709


(a)	Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

See Note 2 for discussion regarding the adoption of ASU No. 2017-07 and its impact to the presentation of pension and other postretirement benefits in the Condensed Consolidated Statements of Income and the Condensed Consolidated Balance Sheets.

NOTE 6. COMMITTED LINES OF CREDIT

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2021. The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31,			December 31,
	2018			2017
Balance outstanding at end of period (1)	$	50,000		$	105,000
Letters of credit outstanding at end of period	$	35,420		$	34,420
Average interest rate at end of period	2.56		%	2.26		%


(1)	As of March 31, 2018 and December 31, 2017, the balance outstanding was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. As of March 31, 2018 and December 31, 2017, there were no borrowings or letters of credit outstanding under this committed line of credit. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

NOTE 7. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.

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The distribution rates paid were as follows during the three months ended March 31, 2018 and the year ended December 31, 2017:



	March 31,		December 31,
	2018		2017
Low distribution rate	2.36	%	1.81	%
High distribution rate	2.88	%	2.36	%
Distribution rate at the end of the period	2.88	%	2.36	%

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

NOTE 8. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion and material capital leases) and long-term debt to affiliated trusts are reported at carrying value on the Condensed Consolidated Balance Sheets.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

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The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 (dollars in thousands):



	March 31, 2018				December 31, 2017
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	951,000	$	1,077,127	$	951,000	$	1,067,783
Long-term debt (Level 3)	767,000		768,947		767,000		810,598
Snettisham capital lease obligation (Level 3)	59,111		58,700		59,745		61,700
Long-term debt to affiliated trusts (Level 3)	51,547		40,722		51,547		41,882

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 79.00 to 129.85, where a par value of 100.0 represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham capital lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on March 31, 2018.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 at fair value on a recurring basis (dollars in thousands):



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
March 31, 2018
Assets:
Energy commodity derivatives	$	—	$	60,025	$	—	$	(59,064	)	$	961
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		47		(47		)	—
Foreign currency exchange derivatives	—		22		—		(6		)	16
Interest rate swap derivatives	—		14,715		—		(1,631		)	13,084
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,663		—		—		—			1,663
Equity securities (2)	6,810		—		—		—			6,810
Total	$	8,473	$	74,762	$	47	$	(60,748	)	$	22,534
Liabilities:
Energy commodity derivatives	$	—	$	77,218	$	—	$	(75,660	)	$	1,558
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		2,852		(47		)	2,805
Power exchange agreement	—		—		10,163		—			10,163
Power option agreement	—		—		5		—			5
Foreign currency exchange derivatives	—		6		—		(6		)	—
Interest rate swap derivatives	—		55,731		—		(29,261		)	26,470
Total	$	—	$	132,955	$	13,020	$	(104,974	)	$	41,001

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	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2017
Assets:
Energy commodity derivatives	$	—	$	43,814	$	—	$	(42,550	)	$	1,264
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		183		(183		)	—
Foreign currency exchange derivatives	—		32		—		(1		)	31
Interest rate swap derivatives	—		7,477		—		(2,574		)	4,903
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,638		—		—		—			1,638
Equity securities (2)	6,631		—		—		—			6,631
Total	$	8,269	$	51,323	$	183	$	(45,308	)	$	14,467
Liabilities:
Energy commodity derivatives	$	—	$	71,342	$	—	$	(69,988	)	$	1,354
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		3,347		(183		)	3,164
Power exchange agreement	—		—		13,245		—			13,245
Power option agreement	—		—		19		—			19
Foreign currency exchange derivatives	—		1		—		(1		)	—
Interest rate swap derivatives	—		73,513		—		(37,544		)	35,969
Total	$	—	$	144,856	$	16,611	$	(107,716	)	$	53,751


(1)	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.


(2)	These assets are trading securities and are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 4 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.

To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.

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Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.2 million as of March 31, 2018 and December 31, 2017.

Level 3 Fair Value

Under the power exchange agreement the Company purchases power at a price that is based on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement, the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price.

For the power commodity option agreement, which expires in June 2019, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges) and 2) estimated delivery volumes. Significant increases or decreases in these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices are accompanied by directionally similar changes in the strike price assumptions used in the calculation.

For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of March 31, 2018 (dollars in thousands):



	Fair Value (Net) at
	March 31, 2018			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(10,163	)	Surrogate facility pricing	O&M charges	$38.87-$45.20/MWh (1)
					Escalation factor	5% - 2018 to 2019
					Transaction volumes	42,682 - 396,984 MWhs
Power option agreement	$	(5	)