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 June 30, ~~2017~~2018

OR

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

For the transition period from to

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3010 W. 69^th Street, Sioux Falls, South Dakota		57108
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Large Accelerated Filer x	Accelerated Filer o	Non-accelerated Filer o	Smaller Reporting Company o	Emerging Growth Company o
		(Do not check if smaller reporting 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. Yes o No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common Stock, Par Value $0.01

~~48,471,447~~50,316,536 shares outstanding at July ~~21, 2017~~13, 2018

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX



		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017	5
	Condensed Consolidated Balance Sheets — June 30, ~~2017~~2018 and December 31, ~~2016~~2017	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017	7
	Condensed Consolidated Statements of Shareholders' Equity — Six Months Ended June 30, ~~2017~~2018 and ~~2016~~2017	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5352
Item 4.	Controls and Procedures	5453
PART II. OTHER INFORMATION		5554
Item 1.	Legal Proceedings	5554
Item 1A.	Risk Factors	5554
Item 6.	Exhibits	61
SIGNATURES		62

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;

changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;

unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and

adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.



PART 1. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenues
Electric	$	233,866		$	248,403		$	500,105		$	489,745		$	209,755		$	233,866		$	448,097		$	500,105
Gas	49,993			44,717			151,066			135,914			52,062			49,993			155,222			151,066
Total Revenues	283,859			293,120			651,171			625,659			261,817			283,859			603,319			651,171
Operating Expenses
Cost of sales	84,000			81,693			203,817			197,127			32,190			84,000			128,267			203,817
Operating, general and administrative	75,188			72,579			156,150			152,440			73,834			72,601			148,179			150,935
Property and other taxes	39,481			35,208			79,409			70,629			43,042			39,481			85,855			79,409
Depreciation and depletion	41,495			39,898			82,956			79,788			43,541			41,495			87,296			82,956
Total Operating Expenses	240,164			229,378			522,332			499,984			192,607			237,577			449,597			517,117
Operating Income	43,695			63,742			128,839			125,675			69,210			46,282			153,722			134,054
Interest Expense, net	(23,408		)	(26,421		)	(46,808		)	(50,930		)	(23,197		)	(23,408		)	(46,167		)	(46,808		)
Other Income	2,123			1,195			3,623			4,297
Other Income (Expense), net													876			(464		)	(253		)	(1,592		)
Income Before Income Taxes	22,410			38,516			85,654			79,042			46,889			22,410			107,302			85,654
Income Tax Expense	(580		)	(2,947		)	(7,257		)	(3,606		)	(3,102		)	(580		)	(5,016		)	(7,257		)
Net Income	$	21,830		$	35,569		$	78,397		$	75,436		$	43,787		$	21,830		$	102,286		$	78,397

Average Common Shares Outstanding	48,451			48,309			48,418			48,275			49,869			48,451			49,644			48,418
Basic Earnings per Average Common Share	$	0.45		$	0.74		$	1.62		$	1.57		$	0.88		$	0.45		$	2.06		$	1.62
Diluted Earnings per Average Common Share	$	0.44		$	0.73		$	1.61		$	1.55		$	0.87		$	0.44		$	2.05		$	1.61
Dividends Declared per Common Share	$	0.525		$	0.50		$	1.05		$	1.00		$	0.55		$	0.525		$	1.10		$	1.05

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)


	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016			2018		2017			2018		2017
Net Income	$	21,830		$	35,569	$	78,397		75,436			$	43,787	$	21,830		$	102,286	78,397
Other comprehensive income (loss), net of tax:
Other comprehensive income, net of tax:
Foreign currency translation	(104		)	8		(53		)	(110		)	86		(104		)	181		(53		)
Reclassification of net losses on derivative instruments	93			37		186			74			113		93			226		186
Total Other Comprehensive (Loss) Income	(11		)	45		133			(36		)
Total Other Comprehensive Income (Loss)												199		(11		)	407		133
Comprehensive Income	$	21,819		$	35,614	$	78,530		$	75,400		$	43,986	$	21,819		$	102,693	$	78,530

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)


	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
ASSETS
Current Assets:
Cash and cash equivalents	$	16,859		$	5,079		$	5,569		$	8,473
Restricted cash	5,608			4,426			7,343			3,556
Accounts receivable, net	123,925			159,556			129,975			182,282
Inventories	50,599			49,206			46,698			52,432
Regulatory assets	35,898			50,041			27,551			37,669
Other	15,128			11,887			14,784			11,947
Total current assets	248,017			280,195			231,920			296,359
Property, plant, and equipment, net	4,261,983			4,214,892			4,417,662			4,358,265
Goodwill	357,586			357,586			357,586			357,586
Regulatory assets	641,720			602,943			375,962			354,316
Other noncurrent assets	47,626			43,705			55,844			54,391
Total Assets	$	5,556,932		$	5,499,321		$	5,438,974		$	5,420,917
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	2,053			$	1,979		2,212			$	2,133
Short-term borrowings	303,658			300,811			—			319,556
Accounts payable	55,530			79,311			56,559			85,160
Accrued expenses	200,517			205,370			215,373			210,047
Regulatory liabilities	16,670			26,361			25,667			15,342
Total current liabilities	578,428			613,832			299,811			632,238
Long-term capital leases	23,320			24,346			21,107			22,213
Long-term debt	1,793,797			1,793,338			2,009,827			1,793,416
Deferred income taxes	615,510			575,582			365,840			340,729
Noncurrent regulatory liabilities	406,305			396,225			442,686			417,701
Other noncurrent liabilities	430,975			419,771			401,972			415,705
Total Liabilities	3,848,335			3,823,094			3,541,243			3,622,002
Commitments and Contingencies (Note 12)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 52,091,239 and 48,470,756 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	521			520
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 53,889,410 and 50,315,374 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued							539			530
Treasury stock at cost	(96,689		)	(95,769		)	(95,768		)	(96,376		)
Paid-in capital	1,389,426			1,384,271			1,494,940			1,445,181
Retained earnings	424,920			396,919			508,528			458,352
Accumulated other comprehensive loss	(9,581		)	(9,714		)	(10,508		)	(8,772		)
Total Shareholders' Equity	1,708,597			1,676,227			1,897,731			1,798,915
Total Liabilities and Shareholders' Equity	$	5,556,932		$	5,499,321		$	5,438,974		$	5,420,917

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
OPERATING ACTIVITIES:
Net income	$	78,397		$	75,436		$	102,286		$	78,397
Items not affecting cash:
Depreciation and depletion	82,956			79,788			87,296			82,956
Amortization of debt issue costs, discount and deferred hedge gain	2,392			1,987			2,333			2,392
Stock-based compensation costs	3,826			3,361			3,738			3,826
Equity portion of allowance for funds used during construction	(2,298		)	(1,608		)	(1,531		)	(2,298		)
(Gain) loss on disposition of assets	(401		)	1,054
Loss (gain) on disposition of assets							11			(401		)
Deferred income taxes	6,320			3,722			5,019			6,320
Changes in current assets and liabilities:
Restricted cash	(1,182		)	46
Accounts receivable	35,631			38,577			52,307			35,631
Inventories	(1,393		)	3,535			5,734			(1,393		)
Other current assets	(3,241		)	(7,365		)	(2,801		)	(3,241		)
Accounts payable	(19,788		)	(17,595		)	(23,849		)	(19,788		)
Accrued expenses	(4,853		)	786			5,266			(4,853		)
Regulatory assets	14,143			10,865			10,118			14,143
Regulatory liabilities	(9,691		)	(55,614		)	10,325			(9,691		)
Other noncurrent assets	(6,781		)	(3,099		)	(3,908		)	(6,781		)
Other noncurrent liabilities	3,767			7,118			(5,217		)	3,767
Cash Provided by Operating Activities	177,804			140,994			247,127			178,986
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(119,123		)	(121,246		)	(116,456		)	(119,123		)
Acquisitions							(18,517		)	—
Proceeds from sale of assets	379			137			—			379
Cash Used in Investing Activities	(118,744		)	(121,109		)	(134,973		)	(118,744		)
FINANCING ACTIVITIES:
Treasury stock activity	411			(1,614		)	1,773			411
Proceeds from issuance of common stock, net							44,865			—
Dividends on common stock	(50,396		)	(47,865		)	(54,253		)	(50,396		)
Issuance of long-term debt	—			60,000
Repayments on long-term debt	—			(55,000		)
Issuances of short-term borrowings, net	2,847			26,932
Line of credit borrowings							1,129,000			—
Line of credit repayments							(913,000		)	—
(Repayments) issuances of short-term borrowings, net							(319,556		)	2,847
Financing costs	(142		)	(5,349		)	(100		)	(142		)
Cash Used in Financing Activities	(47,280		)	(22,896		)	(111,271		)	(47,280		)
Increase (Decrease) in Cash and Cash Equivalents	11,780			(3,011		)
Cash and Cash Equivalents, beginning of period	5,079			11,980
Cash and Cash Equivalents, end of period	$	16,859		$	8,969
Increase in Cash, Cash Equivalents, and Restricted Cash							883			12,962
Cash, Cash Equivalents, and Restricted Cash, beginning of period							12,029			9,505
Cash, Cash Equivalents, and Restricted Cash, end of period							$	12,912		$	22,467
Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Cash paid during the period for:
Income taxes	$	61		$	(2,922	)	$	55		$	61
Interest	40,280			42,861			38,890			40,280
Significant non-cash transactions:
Capital expenditures included in accounts payable	9,776			11,054			11,266			9,776

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(Unaudited)

(in thousands, except per share data)


	Number of Common Shares	Number of Treasury Shares		Common Stock		Paid in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance at December 31, 2015	51,789	3,617		$	518	$	1,376,291		$	(93,948	)	$	325,909		$	(8,596	)	$	1,600,174

Net income	—	—		—		—			—			75,436			—			75,436
Accounting standard adoption	—	—		—		—			—			2,603			—			2,603
Foreign currency translation adjustment	—	—		—		—			—			—			(110		)	(110		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—		—		—			—			—			74			74
Stock-based compensation	167	28		—		4,065			(2,317		)	—			—			1,748
Issuance of shares	—	—		2		(11		)	—			—			—			(9		)
Dividends on common stock ($1.00 per share)	—	—		—		—			—			(47,865		)	—			(47,865		)
Balance at June 30, 2016	51,956	3,645		$	520	$	1,380,345		$	(96,265	)	$	356,083		$	(8,632	)	$	1,632,051
																					Number of Common Shares	Number of Treasury Shares		Common Stock		Paid in Capital		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance at December 31, 2016	51,958	3,626		$	520	$	1,384,271		$	(95,769	)	$	396,919		$	(9,714	)	$	1,676,227		51,958	3,626		$	520	$	1,384,271	$	(95,769	)	$	396,919		$	(9,714	)	$	1,676,227

Net income	—	—		—		—			—			78,397			—			78,397			—	—		—		—		—			78,397			—			78,397
Foreign currency translation adjustment	—	—		—		—			—			—			(53		)	(53		)	—	—		—		—		—			—			(53		)	(53		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—		—		—			—			—			186			186			—	—		—		—		—			—			186			186
Stock-based compensation	133	(6	)	1		5,155			(920		)	—			—			4,236			133	(6	)	1		5,155		(920		)	—			—			4,236
Dividends on common stock ($1.05 per share)	—	—		—		—			—			(50,396		)	—			(50,396		)	—	—		—		—		—			(50,396		)	—			(50,396		)
Balance at June 30, 2017	52,091	3,620		$	521	$	1,389,426		$	(96,689	)	$	424,920		$	(9,581	)	$	1,708,597		52,091	3,620		$	521	$	1,389,426	$	(96,689	)	$	424,920		$	(9,581	)	$	1,708,597

Balance at December 31, 2017																					52,981	3,609		$	530	$	1,445,181	$	(96,376	)	$	458,352		$	(8,772	)	$	1,798,915

Net income																					—	—		—		—		—			102,286			—			102,286
Foreign currency translation adjustment																					—	—		—		—		—			—			181			181
Reclassification of net losses on derivative instruments from OCI to net income, net of tax																					—	—		—		—		—			—			226			226
Reclassification of certain tax effects from AOCL																					—	—		—		—		—			2,143			(2,143		)	—
Stock-based compensation																					72	(35	)	—		4,903		608			—			—			5,511
Issuance of shares																					836	—		9		44,856		—			—			—			44,865
Dividends on common stock ($1.10 per share)																					—	—		—		—		—			(54,253		)	—			(54,253		)
Balance at June 30, 2018																					53,889	3,574		$	539	$	1,494,940	$	(95,768	)	$	508,528		$	(10,508	)	$	1,897,731

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)

(Unaudited)


(1)	Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately ~~709,600~~718,300 customers in Montana, South Dakota and Nebraska.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to June 30, ~~2017~~2018, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the ~~Securities and Exchange Commission.~~SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017.

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain qualifying co-generation facilities and qualifying small power production facilities (QF). We identified one QF contract that may constitute a VIE. We entered into a 40-year power purchase contract in 1984 with this 35 ~~Megawatt~~ megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per ~~Megawatt Hour~~megawatt hour (MWH) ~~(energy payment)~~. After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately ~~$233.1~~$183.3 million through ~~2024~~.

~~(2) New Accounting Standards~~2024.

Accounting Standards Adopted

~~Stock Compensation~~ - During the fourth quarter of 2016, we early adopted the provisions of Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. As a result of this adoption, during the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense and a $0.04 increase in our earnings per share in the Condensed Consolidated Statement of Income. In addition, we recorded a cumulative-effect adjustment to retained earnings as of the date of adoption of $2.6 million in the Condensed Consolidated Balance Sheets. The guidance also requires that in future filings that include the previously issued interim financial

information, the interim financial information is presented on a recast basis to reflect the adoption of ASU 2016-09 as of January 1, 2016. The Condensed Consolidated Financial Statements for the six months ended June 30, 2016, have been recast to reflect this adoption, resulting in an increase in net income and earnings per share.

~~Accounting Standards Issued~~

Revenue Recognition - In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which ~~will supersede~~supersedes nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers.

We ~~expect to adopt~~adopted this standard ~~for interim and annual periods beginning~~as of January 1, 2018, as required, and ~~plan to use~~used the modified retrospective method of ~~adoption. This method requires~~adoption, with no material impact on our financial statements or internal controls. We have also elected to utilize certain practical expedients, which allow us to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all

modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. We completed a comprehensive review of contracts and their associated terms and conditions. Based on this analysis, we did not have a cumulative-effect adjustment to ~~be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new~~retained earnings at January 1, 2018. See Note 2 - Revenue from Contracts with Customers, for additional disclosures including revenue recognition ~~guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.~~

Our revenues are primarily from tariff based sales, which are in the scope of the guidance. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (‘at-will’). We expect that the revenue from these arrangements will be equivalent to the electricity or gas supplied and billed in that period (including estimated billings). As such, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. In our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the guidance on our ability to recognize revenue for certain contracts where collectability is uncertain. The final resolution of these issues and completion of our assessment could impact our current accounting policies and our disaggregated revenue ~~recognition.~~by segment for each geographical region.

Retirement Benefits - ~~- In March 2017,~~On January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the ~~FASB~~Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, as issued ~~new guidance on~~by the ~~presentation~~FASB. Under this ASU, companies are required to disaggregate the current service cost component from the other components of net periodic benefit cost and present it with other current compensation costs for related ~~to benefit plans. The new guidance requires~~employees in the income statement and present the other components elsewhere in the income statement and outside of income from operations. In addition, only the service cost component of net periodic benefit cost ~~to be included within operating income within~~is eligible for capitalization.

ASU 2017-07 was applied on a modified retrospective basis for the ~~same line as other compensation expenses. All~~presentation of the other components of net periodic ~~costs must be outside~~benefit cost in the Condensed Consolidated Statements of ~~operating income. In addition,~~Income. Using the ~~updated guidance permits only~~allowed practical expedient, we applied the ~~service cost component~~amounts disclosed in the “Employee Benefit Plans” note to the 2017 Consolidated Financial Statements for the restatement of ~~net periodic costs to be capitalized to inventory or property, plant and equipment. This represents a change from current accounting and financial reporting, with presentation~~comparative information. The impact of the ~~aggregate net periodic benefit costs on~~adoption of this guidance resulted in the ~~income statement within operating income, and which permits all~~reclassification of the other components of net ~~periodic costs~~benefit cost from operating, general, and administrative expense to ~~be capitalized.~~other expense, net in the Condensed Consolidated Statements of Income. The following table summarizes the adjustments made to conform prior period classifications to the new guidance (in thousands):

~~This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be~~



	Three Months Ended June 30, 2017
	As Reported		Effect of Accounting Change			As Adjusted

Operating, general and administrative	$	75,188	$	(2,587	)	$	72,601
Other Income (Expense), net	2,123		(2,587		)	(464		)



	Six Months Ended June 30, 2017
	As Reported		Effect of Accounting Change			As Adjusted

Operating, general and administrative	$	156,150	$	(5,215	)	$	150,935
Other Income (Expense), net	3,623		(5,215		)	(1,592		)



	As Reported		Effect of Accounting Change			As Adjusted
	Year Ended December 31, 2017

Operating, general and administrative	$	305,137	$	(10,334	)	$	294,803
Other Income (Expense), net	6,919		(10,334		)	(3,415		)

	Year Ended December 31, 2016

Operating, general and administrative	$	302,893	$	(9,030	)	$	293,863
Other Income (Expense), net	5,548		(9,030		)	(3,482		)

	Year Ended December 31, 2015

Operating, general and administrative	$	297,475	$	(6,757	)	$	290,718
Other Income (Expense), net	7,583		(6,757		)	826

ASU 2017-07 was applied ~~retrospectively for the presentation of the various components of net periodic costs and~~ prospectively for the ~~change~~capitalization of related costs in ~~eligible costs to be capitalized. We~~assets and did not have ~~not yet fully determined the impacts of adoption of the standard, but expect that as~~a material impact. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment.

Statement of Cash Flows - In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. We adopted this standard as of January 1, 2018, with no material impact to our Condensed Consolidated Statements of Cash Flows, and although the guidance requires retrospective treatment, we did not have any cash receipts or payments during the prior year that needed to be reclassified.

In November 2016, the FASB issued guidance that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted this standard as of January 1, 2018 with retrospective application. For the six months ended June 30, 2017, this change resulted in a $4.4 million and $5.6 million increase in cash, cash equivalents and restricted cash at the beginning and end of the period on our Condensed Consolidated Statements of Cash Flows, respectively. In addition, removing the change in restricted cash from operating activities in the Condensed Consolidated Statements of Cash Flows resulted in an increase of $1.2 million in our cash provided by operating activities for the six months ended June 30, 2017.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):



	June 30, 2018		December 31, 2017		June 30, 2017		December 31, 2016		December 31, 2015
Cash and cash equivalents	$	5,569	$	8,473	$	16,859	$	5,079	$	11,980
Restricted cash	7,343		3,556		5,608		4,426		6,634
Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	12,912	$	12,029	$	22,467	$	9,505	$	18,614

Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.

Stranded Tax Effects in Accumulated Other Comprehensive Loss - In February 2018, the FASB issued guidance to allow a one-time reclassification from accumulated other comprehensive loss (AOCL) to retained earnings for stranded tax effects

resulting from the new tax reform legislation. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCL.

This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim reporting period for which financial statements have not yet been issued. We early adopted this guidance during the first quarter of 2018, through a one-time reclassification of $2.1 million of stranded tax effects from AOCL to retained earnings. Adoption of this guidance did not have a material impact on our condensed consolidated financial position, results of operations or cash flows.

Accounting Standards Issued

Leases - In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us ~~in our first quarter of~~for interim and annual periods beginning January 1, 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. An additional transition approach allows an entity to not assess on transition whether any expired or existing land easements are, or contain, leases that were not previously accounted for as leases. In addition, our easements are entered into in perpetuity and do not meet the definition of a lease in accordance with this guidance. We are currently evaluating the impact of adoption of this guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our ~~initial~~ analysis to this point we do not expect this guidance to have a significant impact on our Financial Statements and disclosures other than an expected increase in assets and liabilities.

(2) Revenue from Contracts with Customers

~~Statement of Cash Flows~~Accounting Policy ~~- In August 2016,~~

Our revenues are primarily from tariff based sales. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the ~~FASB issued guidance that addresses eight classification issues related~~revenue from these arrangements is equivalent to the ~~presentation of cash receipts~~electricity or gas supplied and ~~cash payments~~billed in that period (including estimated billings), there will not be a shift in the ~~statement~~timing or pattern of ~~cash flows. The new guidance~~revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and will ~~be effective~~also not have a shift in the timing or pattern of revenue recognition.

Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for uselectric and natural gas services delivered to customers, but not yet billed at month-end.

Nature of Goods and Services

We currently provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which include single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products.

Electric Segment- Our regulated electric utility business primarily provides generation, transmission, and distribution services to our customers in our ~~first quarter of 2018, with early adoption permitted.~~Montana and South Dakota jurisdictions. We ~~are currently evaluating~~recognize revenue when electricity is delivered to the ~~impact of adoption of this guidance~~customer. Payments on our ~~Statement of Cash Flows.~~tariff based sales are generally due in 20-30 days after the billing date.

Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission and distribution services to our customers in our Montana, South Dakota, and Nebraska jurisdictions. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date.

Disaggregation of Revenue

The following tables disaggregate our revenue by major source and customer class (in millions):



	Three Months Ended
	June 30, 2018									June 30, 2017
	Electric			Natural Gas			Total			Electric		Natural Gas		Total

Montana	$	59.5		$	17.6		$	77.1		$	59.7	$	16.5	$	76.2
South Dakota	14.4			5.6			20.0			12.9		4.3		17.2
Nebraska	—			5.0			5.0			—		4.1		4.1
Residential	73.9			28.2			102.1			72.6		24.9		97.5
Montana	79.6			8.8			88.4			83.0		8.2		91.2
South Dakota	22.3			3.6			25.9			21.4		2.8		24.2
Nebraska	—			2.4			2.4			—		2.1		2.1
Commercial	101.9			14.8			116.7			104.4		13.1		117.5
Industrial	10.7			0.2			10.9			10.1		0.2		10.3
Lighting, Governmental, and Irrigation	7.1			0.2			7.3			8.9		0.1		9.0
Total Customer Revenues	193.6			43.4			237.0			196.0		38.3		234.3
Other Tariff and Contract Based Revenues	17.8			10.6			28.4			33.8		9.7		43.5
Total Revenue from Contracts with Customers	211.4			54.0			265.4			229.8		48.0		277.8

Regulatory amortization	(1.7		)	(1.9		)	(3.6		)	4.1		2.0		6.1
Total Revenues	$	209.7		$	52.1		$	261.8		$	233.9	$	50.0	$	283.9



	Six Months Ended
	June 30, 2018									June 30, 2017
	Electric			Natural Gas			Total			Electric			Natural Gas			Total

Montana	$	146.7		$	58.5		$	205.2		$	150.5		$	60.3		$	210.8
South Dakota	33.1			17.0			50.1			30.2			15.1			45.3
Nebraska	—			16.4			16.4			—			13.1			13.1
Residential	179.8			91.9			271.7			180.7			88.5			269.2
Montana	163.3			29.4			192.7			171.1			30.1			201.2
South Dakota	46.3			11.5			57.8			43.8			10.2			54.0
Nebraska	—			8.5			8.5			—			7.0			7.0
Commercial	209.6			49.4			259.0			214.9			47.3			262.2
Industrial	21.5			0.7			22.2			21.0			0.7			21.7
Lighting, Governmental, and Irrigation	12.1			0.7			12.8			14.1			0.6			14.7
Total Customer Revenues	423.0			142.7			565.7			430.7			137.1			567.8
Other Tariff and Contract Based Revenues	35.6			20.9			56.5			71.2			20.8			92.0
Total Revenue from Contracts with Customers	458.6			163.6			622.2			501.9			157.9			659.8

Regulatory amortization	(10.5		)	(8.4		)	(18.9		)	(1.8		)	(6.8		)	(8.6		)
Total Revenues	$	448.1		$	155.2		$	603.3		$	500.1		$	151.1		$	651.2

(3) Acquisition

Montana Wind Generation

In ~~November 2016,~~June 2018, we completed the ~~FASB issued guidance that a statement~~purchase of ~~cash flows explain~~ the ~~change during~~9.7 MW Two Dot wind project near Two Dot, Montana for approximately $18.5 million. The Two Dot purchase price was allocated based on the ~~period in~~estimated fair values of the ~~total~~assets acquired and liabilities assumed at the date of ~~cash, cash equivalents, and amounts generally described~~the acquisition as restricted cash or restricted cash equivalents. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows.follows (in thousands):



Purchase Price Allocation
Assets Acquired
Property Plant and Equipment, net	$	18,542
Current Assets	35
Total Assets Acquired	18,577

Liabilities Assumed
Accrued Expenses	60
Total Liabilities Assumed	60

Total Purchase Price	$	18,517

~~(3)~~(4) Regulatory Matters

~~Montana Natural Gas General Rate Filing~~Tax Cuts and Jobs Act

In December 2017, H.R.1 (the Tax Cuts and Jobs Act) was signed into law, which enacts significant changes to U.S. tax and related laws. The primary impact to us is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. Our Montana and South Dakota Tax Cuts and Jobs Act filings are discussed below. Dockets have also been opened in our Federal Energy Regulatory Commission (FERC) and Nebraska jurisdictions, where we proposed using reduced revenue requirements from the impacts of the Tax Cuts and Jobs Act to defer planned future rate filings in both jurisdictions. In each of our jurisdictions, we expect the Tax Cuts and Jobs Act related credits to continue and be subject to true-up until base rates are reset in a general rate case filing or agreement is reached with our state regulatory commissions as to how the impact of the Tax Cuts and Job Act will be resolved.

As of June ~~2017,~~30, 2018, we ~~reached~~have deferred revenue of approximately $13.5 million associated with the impacts of the Tax Cuts and Jobs Act. For purposes of the filings discussed below, we calculated the customer benefit using two alternate methods based on current and historic test periods. The revenue deferral is based upon our 2018 estimated impact of Tax Cuts and Jobs Act of approximately $18 million to $23 million and is offset by a ~~settlement agreement~~corresponding reduction in income tax expense. Application of the historic method would result in customer refunds that exceed the reduction in our 2018 taxes, which would be an additional reduction in pretax earnings and cash flows ranging from approximately $5 million to $10 million.

Montana - In March 2018, we submitted a filing to the Montana Public Service Commission (MPSC) calculating the estimated benefit of the Tax Cuts and Jobs Act related savings to customers using two alternative methods. The first method was calculated based on the expected income tax expense reduction in 2018, with ~~intervenors~~no impact to net income. The second method was calculated by revising the electric and natural gas revenue requirements in the last applicable test years. For our electric customers, we proposed to use 50% of the benefit as a direct refund to customers, and to use the other 50% to remove trees outside our electric transmission and distribution lines rights of way, which pose risks to our system including disruption of service, property damage, and / or forest fires. We have begun work to remove trees outside our right of way, and as of June 30, 2018, have deferred $0.3 million of costs, which is recorded in the Condensed Consolidated Balance Sheets to reflect the impacts of the Tax Cuts and Jobs Act, subject to MPSC approval. For our natural gas ~~rate case. This settlement included an overall increase~~customers, we proposed to use the benefit as a direct refund to customers.

South Dakota - In April 2018, we submitted a filing with the South Dakota Public Utilities Commission (SDPUC) calculating the estimated benefit of the Tax Cuts and Jobs Act related savings to customers based on the expected income tax expense reduction in ~~delivery services~~2018, with no impact to net income. We also presented a calculation revising the electric and production charges of approximately $5.7 million, based upon a 6.96 percent rate of return (9.55 percent return on equity, 4.67 percent cost of debt and 53.2 percent debt to rate base). In our initial filing in September 2016, we requested an annual increase to natural gas ~~rates of approximately $10.9 million, with rebuttal testimony filed~~revenue requirements in ~~April 2017 supporting~~the last applicable test years. We proposed to either refund the benefit to customers, or to hold this

amount in a ~~revised requested annual increase~~regulatory liability to ~~rates of approximately $9.4 million. The~~provide rate moderation in our next electric and natural gas production part of this filing includes a request for cost-recovery and permanent inclusion in base rates of fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin. Actual production costsrate cases, at the SDPUC’s option. Settlement negotiations are currently ~~recovered~~ongoing. The SDPUC has not established a procedural schedule in ~~customer rates on an interim basis through our supply tracker.~~this docket.

The MPSC held a work session on July 20, 2017, and voted to draft an order accepting the settlement with modifications. We estimate that these modifications lower the increase in delivery services and production charges to approximately $5.1 million. Due to the MPSC's modification of the settlement, any of the parties may elect to withdraw and request a new hearing. We will evaluate the impact of these modifications upon receipt of a final order, which we expect in August 2017.

Montana QF ~~Decision~~Tariff Filing

Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with certain exceptions, to purchase energy and capacity from independent power producers that are QFs. ~~The MPSC held a work session in June 2017 to discuss our~~In May 2016, we filed an application for approval of a revised tariff for standard rates for small ~~QFs.~~QFs (3 MW or less). In ~~July~~November 2017, the MPSC issued an order ~~establishing~~(QF Order) revising the QF tariff to establish a maximum ~~10-year~~ contract length ~~with a rate adjustment after the first five~~of 15 years and ~~approving rates that do not include costs associated with~~substantially lowering the ~~risk of~~rate for future ~~carbon dioxide emissions regulations. We expect this will result in substantially lower rates for these~~QF contracts. In ~~this same order,~~the QF Order, the MPSC ~~indicated they will~~also upheld an initial decision to apply the ~~10-year~~ contract term to ~~us for~~our future owned and contracted electric supply ~~resource transactions.~~resources. We, as well as the QFs, sought judicial review of the QF Order. The matter is now pending before the Montana District Court. The Court is scheduled to hear oral arguments on September 7, 2018.

As a result of the QF Order, we terminated our competitive solicitation process for 20-year resources to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. We continue to evaluate the impact of the QF Order, as we have significant generation capacity deficits and negative reserve ~~margins.~~margins, and our 2015 resource plan identified price and reliability risks to our customers if we rely solely upon market purchases to address these capacity needs. In addition to our responsibility to meet peak demand, national transmission-related reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. ~~Our 2016~~We expect to file our next electric supply resource procurement plan identified price and reliability risks to our customers of solely relying upon market purchases to address these needs. We are evaluating the impact of this decision and have suspended our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in ~~Montana.~~December 2018.

Cost Recovery Mechanisms

Montana House Bill 193 / Electric ~~and Natural Gas~~ Tracker ~~Filings~~

~~House Bill 193~~ - In April 2017, the Montana legislature passed House Bill 193 (HB 193), ~~repealing~~amending the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. ~~In May 2017,~~The revised statute gives the MPSC ~~issued a Notice of Commission Action (NCA) initiating~~discretion whether to approve an electric supply cost adjustment mechanism. The MPSC initiated a process to develop a replacement electric ~~tracker mechanism. We filed a motion for reconsideration of the May 2017 NCA. On July 7, 2017, the MPSC issued an additional NCA addressing the arguments~~supply cost adjustment mechanism, and in our motion for reconsideration and identifying three replacement mechanism alternatives for consideration. Two of the replacement mechanism alternatives identified include updating the fixed rate portion of the recovery of our electric supply assets in addition to the variable costs that were recovered through the prior electric tracker. This would be accomplished through an electric supply revenue requirements filing to be made by us by September 30, 2017. The July 2017 NCA also raises questions regarding our earnings as compared with our authorized rate of return for 2016 for electric supply. As noted below in the hydro compliance filing discussion, our 2016 MPSC annual report indicates we earned less than our authorized rate of return with electric delivery service and supply combined. The NCA established a timeline for the parties to provide commentsresponse, in July ~~2017, on the issue of whether the MPSC should require a September 2017 filing, and we are awaiting a further decision.~~

~~On July 14,~~ 2017, we filed a proposed electric Power Cost and Credit Adjustment Mechanism (PCCAM) ~~with~~. In December 2017, after the ~~MPSC.~~ intervenors filed testimony, the MPSC issued a Notice of Additional Issues stating that the range of options proposed by the parties was not sufficient and directing parties to consider alternatives incorporating risk-sharing features of other utilities in the region.

We ~~believe~~filed testimony in February 2018, responsive to both the ~~PCCAM filing is consistent with~~intervenors' testimony and the MPSC's ~~advocacy for HB 193,~~Notice of Additional Issues addressing alternative risk-sharing mechanisms. Intervenors filed testimony on the ~~MPSC's May~~Notice of Additional Issues in March 2018. The MPSC held a hearing during the second quarter of 2018, and ~~July 2017 NCAs, and~~we expect a decision in the ~~Montana-Dakota Utilities (MDU) Montana adjustment mechanism that allows for recovery~~matter no later than the fourth quarter of ~~90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how~~2018. If the MPSC approves a new mechanism, the MPSC may

apply the ~~statute in establishing a revised mechanism. We expect application of the new~~ mechanism to variable costs ~~to be~~on a retroactive basis to the effective date of HB ~~193.~~193 (July 1, 2017).

Montana Electric Tracker Open Dockets - 2015/2016 - 2016/2017 - 2017/2018 (2015-2018 Tracker Filings) - Under the previous statutory tracker mechanism, each year we submitted an electric tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period, which were subject to a prudency review. ~~In June 2017,~~We continue to submit annual filings, pursuant to our tariff, until the MPSC ~~consolidated the dockets~~approves a new cost recovery mechanism for electricity supply costs. The MPSC has issued three orders approving interim rates for the ~~2015/2016 and 2016/2017 tracker periods, which are approved on an interim basis. The MPSC~~2015-2018 Tracker Filings, but has not established a schedule ~~regarding~~for adjudication of these ~~remaining open dockets under the prior statutory tracker.~~filings.

~~Natural Gas Tracker - 2016/2017~~ ~~- In May 2017, we filed our annual natural gas tracker filing for the 2016/2017 tracker period, which the MPSC approved on an interim basis. HB 193 does not impact our natural gas recovery mechanism.~~

Montana Electric Tracker Litigation - ~~2012/2013 -~~ 2013/2014 ~~(Consolidated Docket) and 2014/2015 (2015 Tracker)~~- In 2016, ~~we received final electric tracker orders from~~ the MPSC issued an order which, in ~~the Consolidated Docket and 2015 Tracker, resulting~~total, resulted in a $12.4 million disallowance of costs, including interest. In June 2016, we filed an appeal in Montana District Court (Lewis & Clark County) of the MPSC decision in our 2015 Tracker docket to disallow certain portfolio modeling costs. Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket regarding theThe order included a disallowance of replacement power costs from a 2013 outage at Colstrip Unit ~~4 and~~4. In September 2016, we appealed that order to the ~~modeling/planning costs,~~Montana District Court, arguing that ~~these decisions were~~the order was arbitrary and capricious and violated Montana law. We brought this action in Montana District Court, as well (Yellowstone County). In the Consolidated Docket appeal, we abandoned our appeal of the modeling costs (approximately $0.3 million) reserving the issue for our 2015 Tracker appeal. The briefing in the Consolidated Docket appeal concluded in May 2017, and we expect a decision on this appeal within the next ~~12 months. We expect a decision in the 2015 Tracker appeal in the next 12 to 18~~nine months.

~~Hydro Compliance Filing~~

~~In December 2015, we submitted the required compliance filing associated with our 2014 purchase of~~ Montana hydroelectric (hydro) generation assets, to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In December 2016, the MPSC issued a final order in this filing reducing the annual amountProperty Tax Tracker - Under Montana law, we are allowed to ~~recover in hydro generation rates by approximately $1.2 million. In addition,~~track the changes in the ~~final order,~~actual level of state and local taxes and fees and recover the ~~MPSC included language requiring us to indicate by April 30, 2017, whether we intend to file a Montana electric rate case based on a 2016 test year.~~

~~On April 26, 2017, we filed our required~~increase in taxes and fees, net of the associated income tax benefit. We submit an annual ~~report~~property tax tracker filing with the MPSC ~~regarding 2016 results, which indicates we earned less than our authorized~~for an automatic rate adjustment, with rates effective January 1st of ~~return. At the same time, we also submitted a filing to~~each year. In January 2018, the MPSC ~~responsive~~issued an order in our 2017 filing applying an alternate allocation methodology both prospectively and retroactively, which reduces our annual recovery of these taxes by approximately $1.7 million. The change in methodology results in a lower property tax allocation to ~~the hydro compliance order, indicating we~~our Montana electric retail customers and a higher property tax allocation to FERC transmission customers (we do not ~~expect to file an electric rate case~~have a property tax tracker for FERC jurisdictional purposes). We sought reconsideration of the retroactive application of this change in ~~2017 based on a 2016 test year. However, we indicated we expect to file a general electric rate case in~~methodology. On June 18, 2018, ~~based on a 2017 test year. In the hydro compliance order,~~ the MPSC ~~indicated that if we do not intend to file a rate case in 2017,~~issued an order applying the MPSC may require us to make an additional financial filing that would facilitate an assessment of whether the MPSC believes additional action would be required to fulfill its obligation to authorize just and reasonable rates.change on

~~FERC Filing -~~

a prospective basis only, resulting in a $1.7 million adjustment to reflect the increase in recovery of Montana property taxes for 2017 in the three months ended June 30, 2018, which is reflected in the Condensed Consolidated Statements of Income.

Dave Gates Generating Station at Mill Creek (DGGS)

In ~~May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying~~2012 a ~~May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012~~ FERC Administrative Law ~~Judge's~~Judge (ALJ) ~~initial~~issued a decision regarding cost allocation at DGGS ~~between retail~~ and ~~wholesale customers. This decision~~ concluded that only a portion of ~~these~~the costs should be allocated to FERC jurisdictional customers. ~~We had cumulative deferred revenue~~In 2016, the FERC denied our request for rehearing of ~~approximately $27.3 million, consistent with~~ the ~~ALJ's initial~~ALJ decision and ordered us to make refunds, which ~~was refunded to wholesale and choice customers~~we did in June ~~2016 in accordance with the FERC order.~~

2016. In ~~June 2016, we filed a petition for review of the FERC's May 2016 order with~~March 2018, the United States Circuit Court of Appeals for the District of Columbia Circuit ~~(D.C. Circuit). The~~denied our petition for review of the FERC's order and the matter is ~~fully briefed, and we are waiting for the Court to set a date for oral argument. We do not expect a decision in this matter until the fourth quarter of 2017, at the earliest.~~now final.

~~(4)~~(5) Income Taxes

The primary impact of the Tax Cuts and Jobs Act is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate ~~of 35% primarily~~ due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production

tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the Tax Cuts and Jobs Act. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):


	Three Months Ended June 30,										Three Months Ended June 30,
	2017					2016					2018					2017
Income Before Income Taxes	$	22,410				$	38,516				$	46,889				$	22,410

Income tax calculated at 35% federal statutory rate	7,844			35.0	%	13,481			35.0	%
Income tax calculated at federal statutory rate											9,846			21.0	%	7,844			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(492		)	(2.2	)	(1,025		)	(2.7	)	801			1.7		(492		)	(2.2	)
Flow-through repairs deductions	(4,753		)	(21.2	)	(6,971		)	(18.1	)	(4,095		)	(8.7	)	(4,753		)	(21.2	)
Production tax credits	(1,459		)	(6.5	)	(2,324		)	(6.0	)	(2,559		)	(5.5	)	(1,459		)	(6.5	)
Plant and depreciation of flow through items	(686		)	(3.1	)	(246		)	(0.6	)	(571		)	(1.2	)	(686		)	(3.1	)
Prior year permanent return to accrual adjustments	—			—		(128		)	(0.3	)
Other, net	126			0.6		160			0.4		(320		)	(0.7	)	126			0.6
	(7,264		)	(32.4	)	(10,534		)	(27.3	)	(6,744		)	(14.4	)	(7,264		)	(32.4	)

Income Tax Expense	$	580		2.6	%	$	2,947		7.7	%	$	3,102		6.6	%	$	580		2.6	%

Six Months Ended June 30,
2017 2016
Income Before Income Taxes $ 85,654
$ 79,042

Income tax calculated at 35% federal statutory rate 29,979
35.0 % 27,665
35.0 %

Permanent or flow through adjustments:
State income, net of federal provisions (1) (1,326 ) (1.5 ) (2,292 ) (2.9 )
Flow-through repairs deductions (13,550 ) (15.8 ) (13,645 ) (17.3 )
Production tax credits (5,290 ) (6.2 ) (5,099 ) (6.5 )
Plant and depreciation of flow through items (2,126 ) (2.5 ) (1,184 ) (1.5 )
Share-based compensation (1) (399 ) (0.5 ) (1,646 ) (2.1 )
Prior year permanent return to accrual adjustments —
—
(128 ) (0.1 )
Other, net (31 ) —
(65 ) —
(22,722 ) (26.5 ) (24,059 ) (30.4 )

Income Tax Expense $ 7,257
8.5 % $ 3,606
4.6 %

(1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the impact of this adoption is reflected as of January 1, 2016, and included in the state income, net of federal provisions, and share-based compensation lines, resulting in a reduction in tax expense for the six months ended June 30, 2016.



	Six Months Ended June 30,
	2018					2017
Income Before Income Taxes	$	107,302				$	85,654

Income tax calculated at 35% federal statutory rate	22,533			21.0	%	29,979			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	1,533			1.5		(1,326		)	(1.5	)
Flow-through repairs deductions	(10,681		)	(10.0	)	(13,550		)	(15.8	)
Production tax credits	(6,447		)	(6.0	)	(5,290		)	(6.2	)
Plant and depreciation of flow through items	(1,487		)	(1.4	)	(2,126		)	(2.5	)
Share-based compensation	275			0.3		(399		)	(0.5	)
Other, net	(710		)	(0.7	)	(31		)	—
	(17,517		)	(16.3	)	(22,722		)	(26.5	)

Income Tax Expense	$	5,016		4.7	%	$	7,257		8.5	%

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately ~~$84.4~~$57.1 million as of June 30, ~~2017~~2018, including approximately $~~66.7~~47.7 million that, if recognized, would impact our effective tax rate. ~~We do not anticipate~~It is reasonably possible that ~~total~~our unrecognized tax benefits ~~will significantly change~~may decrease by up to $20 million in the next 12 months due to the ~~settlement of audits or the~~ expiration of ~~statutes~~statute of ~~limitation within the next twelve months.~~limitation.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2018 and 2017, we recognized $0.6 million and $0.3 million, ~~of expense for interest and penalties in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2016, we recognized $0.3 million~~respectively, of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, we had ~~$1.0~~$2.1 million and ~~$0.7~~$1.5 million, respectively, of interest accrued in the Condensed Consolidated Balance Sheets.

Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service.

~~(5)~~(6) Goodwill

We completed our annual goodwill impairment test as of April 1, ~~2017,~~2018, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

There were no changes in our goodwill during the six months ended June 30, ~~2017.~~2018. Goodwill by segment is as follows for both June 30, ~~2017~~2018 and December 31, ~~2016~~2017 (in thousands):



Electric	$	243,558
Natural gas	114,028
Total	$	357,586

~~(6)~~(7) Comprehensive Income ~~(Loss)~~

The following tables display the components of Other Comprehensive Income, ~~(Loss),~~ after-tax, and the related tax effects (in thousands):

Three Months Ended
June 30, 2017 June 30, 2016
Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount
Foreign currency translation adjustment $ (104 ) $ —
$ (104 ) $ 8
$ —
$ 8
Reclassification of net losses on derivative instruments 153
(60 ) 93
62
(25 ) 37
Other comprehensive income (loss) $ 49
$ (60 ) $ (11 ) $ 70
$ (25 ) $ 45


	Six Months Ended																		Three Months Ended
	June 30, 2017									June 30, 2016									June 30, 2018							June 30, 2017
	Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount		Tax Expense			Net-of-Tax Amount		Before-Tax Amount			Tax Expense			Net-of-Tax Amount
Foreign currency translation adjustment	$	(53	)	$	—		$	(53	)	$	(110	)	$	—		$	(110	)	$	86	$	—		$	86	$	(104	)	$	—		$	(104	)
Reclassification of net losses on derivative instruments	306			(120		)	186			124			(50		)	74			154		(41		)	113		153			(60		)	93
Other comprehensive income (loss)	$	253		$	(120	)	$	133		$	14		$	(50	)	$	(36	)	$	240	$	(41	)	$	199	$	49		$	(60	)	$	(11	)



	Six Months Ended
	June 30, 2018							June 30, 2017
	Before-Tax Amount		Tax Expense			Net-of-Tax Amount		Before-Tax Amount			Tax Expense			Net-of-Tax Amount
Foreign currency translation adjustment	$	181	$	—		$	181	$	(53	)	$	—		$	(53	)
Reclassification of net losses on derivative instruments	307		(81		)	226		306			(120		)	186
Other comprehensive income	$	488	$	(81	)	$	407	$	253		$	(120	)	$	133

Balances by classification included within ~~accumulated other comprehensive loss (AOCL)~~AOCL on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):


	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
Foreign currency translation	$	1,327		$	1,380		$	1,359		$	1,178
Derivative instruments designated as cash flow hedges	(10,166		)	(10,352		)	(9,755		)	(9,981		)
Reclassification of certain tax effects from AOCL							(2,143		)	—
Postretirement medical plans	(742		)	(742		)	31			31
Accumulated other comprehensive loss	$	(9,581	)	$	(9,714	)	$	(10,508	)	$	(8,772	)

The following tables display the changes in AOCL by component, net of tax (in thousands):


		Three Months Ended													Three Months Ended
		June 30, 2017													June 30, 2018
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(10,259	)	$	(742	)	$	1,431		(9,570		)		$	(12,018	)	$	38	$	1,273	$	(10,707	)
Other comprehensive loss before reclassifications		—			—			(104		)	(104		)
Other comprehensive income before reclassifications															—			—		86		86
Amounts reclassified from AOCL	Interest Expense	93			—			—			93			Interest Expense	113			—		—		113
Net current-period other comprehensive income (loss)		93			—			(104		)	(11		)
Net current-period other comprehensive income															113			—		86		199
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)		$	(11,905	)	$	38	$	1,359	$	(10,508	)


		Three Months Ended												Three Months Ended
		June 30, 2016												June 30, 2017
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(8,977	)	$	(937	)	$	1,237	(8,677		)		$	(10,259	)	$	(742	)	$	1,431		(9,570		)
Other comprehensive income before reclassifications		—			—			8		8
Other comprehensive loss before reclassifications														—			—			(104		)	(104		)
Amounts reclassified from AOCL	Interest Expense	37			—			—		37			Interest Expense	93			—			—			93
Net current-period other comprehensive income		37			—			8		45
Net current-period other comprehensive income (loss)														93			—			(104		)	(11		)
Ending balance		$	(8,940	)	$	(937	)	$	1,245	$	(8,632	)		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)


		Six Months Ended													Six Months Ended
		June 30, 2017													June 30, 2018
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(10,352	)	(742		)	$	1,380		(9,714		)		$	(9,981	)	$	31	$	1,178	$	(8,772	)
Other comprehensive loss before reclassifications		—			—			(53		)	(53		)
Other comprehensive income before reclassifications															—			—		181		181
Amounts reclassified from AOCL	Interest Expense	186			—			—			186			Interest Expense	226			—		—		226
Net current-period other comprehensive income (loss)		186			—			(53		)	133
Net current-period other comprehensive income															226			—		181		407
Reclassification of certain tax effects from AOCL															(2,150		)	7		—		(2,143		)
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)		$	(11,905	)	$	38	$	1,359	$	(10,508	)


		Six Months Ended													Six Months Ended
		June 30, 2016													June 30, 2017
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	(937		)	$	1,355		(8,596		)		$	(10,352	)	$	(742	)	$	1,380		$	(9,714	)
Other comprehensive loss before reclassifications		—			—			(110		)	(110		)		—			—			(53		)	(53		)
Amounts reclassified from AOCL	Interest Expense	74			—			—			74			Interest Expense	186			—			—			186
Net current-period other comprehensive income (loss)		74			—			(110		)	(36		)		186			—			(53		)	133
Ending balance		$	(8,940	)	$	(937	)	$	1,245		$	(8,632	)		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)

~~(7) Risk Management and Hedging~~(8) Financing Activities

~~Nature of Our Business and Associated Risks~~

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

~~Objectives and Strategies for Using Derivatives~~

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In ~~addition,~~September 2017, we ~~may use interest rate swaps~~entered into an Equity Distribution Agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J. P. Morgan Securities LLC, collectively the sales agents, pursuant to ~~manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.~~

~~Accounting for Derivative Instruments~~

~~We evaluate new~~which we offered and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

~~Normal Purchases and Normal Sales~~

We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at ~~June 30, 2017~~ ~~and~~ ~~December 31, 2016. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.~~

~~Credit Risk~~

Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

~~Interest Rate Swaps Designated as Cash Flow Hedges~~

We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2017

Interest rate contracts Interest Expense $ 307

~~A pre-tax loss of approximately $16.8 million is remaining in AOCL as of~~ ~~June 30, 2017, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.~~

~~(8) Fair Value Measurements~~

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

~~Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;~~

~~Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and~~

~~Level 3 – Significant inputs that are generally not observable from market activity.~~

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 - Risk Management and Hedging Activities for further discussion.

~~We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.~~

Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value
(in thousands)
June 30, 2017
Restricted cash $ 5,354
$ —
$ —
$ —
$ 5,354
Rabbi trust investments 29,012
—
—
—
29,012
Total $ 34,366
$ —
$ —
$ —
$ 34,366

December 31, 2016
Restricted cash $ 4,164
$ —
$ —
$ —
$ 4,164
Rabbi trust investments 25,064
—
—
—
25,064
Total $ 29,228
$ —
$ —
$ —
$ 29,228

~~Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist~~sold shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended June 30, 2018, we issued 835,765 shares of our common stock at an average price of $54.45, for net proceeds of $44.9 million, which is net of sales commissions and ~~actively traded mutual funds with quoted prices in active markets.~~other fees paid of approximately $0.6 million. These issuances concluded this program. Since inception of the program, we sold 1,724,703 shares of our common stock at an average price of $57.98 per share. Net proceeds received were approximately $98.6 million, which are net of sales commissions and other fees paid of approximately $1.4 million.

~~Financial Instruments~~

~~The estimated fair value of financial instruments is summarized as follows (in thousands):~~

June 30, 2017 December 31, 2016
Carrying Amount Fair Value Carrying Amount Fair Value
Liabilities:
Long-term debt 1,793,797
$ 1,898,482
$ 1,793,338
$ 1,852,052

Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

(9) Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs.

We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions.

Financial data for the business segments are as follows (in thousands):


Three Months Ended
June 30, 2017	Electric			Gas			Other			Eliminations		Total
June 30, 2018															Electric			Gas			Other			Eliminations		Total
Operating revenues	233,866			$	49,993		$	—		$	—	$	283,859		$	209,755		$	52,062		$	—		$	—	$	261,817
Cost of sales	70,146			13,854			—			—		84,000			19,613			12,577			—			—		32,190
Gross margin	163,720			36,139			—			—		199,859			190,142			39,485			—			—		229,627
Operating, general and administrative	54,086			20,206			896			—		75,188			52,894			19,650			1,290			—		73,834
Property and other taxes	30,909			8,569			3			—		39,481			33,880			9,160			2			—		43,042
Depreciation and depletion	34,105			7,382			8			—		41,495			36,139			7,394			8			—		43,541
Operating income (loss)	44,620			(18		)	(907		)	—		43,695
Operating income															67,229			3,281			(1,300		)	—		69,210
Interest expense	(21,064		)	(1,500		)	(844		)	—		(23,408		)	(20,318		)	(1,161		)	(1,718		)	—		(23,197		)
Other income	917			489			717			—		2,123
Other (expense) income															(52		)	(191		)	1,119			—		876
Income tax (expense) benefit	(523		)	817			(874		)	—		(580		)	(2,649		)	492			(945		)	—		(3,102		)
Net income (loss)	$	23,950		$	(212	)	$	(1,908	)	$	—	$	21,830		$	44,210		$	2,421		$	(2,844	)	$	—	$	43,787
Total assets	$	4,439,694		$	1,114,426		$	2,812		—		$	5,556,932		$	4,351,359		$	1,072,173		$	15,442		$	—	$	5,438,974
Capital expenditures	$	55,995		$	11,609		$	—		—		$	67,604		$	52,844		$	11,607		$	—		$	—	$	64,451

Three Months Ended
June 30, 2016 Electric Gas Other Eliminations Total
Operating revenues $ 248,403
$ 44,717
$ —
$ —
$ 293,120
Cost of sales 72,165
9,528
—
—
81,693
Gross margin 176,238
35,189
—
—
211,427
Operating, general and administrative 51,568
20,585
426
—
72,579
Property and other taxes 27,322
7,883
3
—
35,208
Depreciation and depletion 32,544
7,346
8
—
39,898
Operating income (loss) 64,804
(625 ) (437 ) —
63,742
Interest expense (24,119 ) (1,814 ) (488 ) —
(26,421 )
Other income 687
271
237
—
1,195
Income tax (expense) benefit (3,331 ) 1,278
(894 ) —
(2,947 )
Net income (loss) $ 38,041
$ (890 ) $ (1,582 ) $ —
$ 35,569
Total assets $ 4,221,293
$ 1,080,065
$ 6,248
$ —
$ 5,307,606
Capital expenditures $ 57,938
$ 11,990
$ —
$ —
$ 69,928

Six Months Ended
June 30, 2017 Electric Gas Other Eliminations Total
Operating revenues 500,105
$ 151,066
$ —
$ —
$ 651,171
Cost of sales 155,531
48,286
—
—
203,817
Gross margin 344,574
102,780
—
—
447,354
Operating, general and administrative 112,705
41,835
1,610
—
156,150
Property and other taxes 62,070
17,333
6
—
79,409
Depreciation and depletion 68,175
14,765
16
—
82,956
Operating income (loss) 101,624
28,847
(1,632 ) —
128,839
Interest expense (42,101 ) (3,046 ) (1,661 ) —
(46,808 )
Other income 1,623
717
1,283
—
3,623
Income tax (expense) benefit (3,410 ) (6,134 ) 2,287
—
(7,257 )
Net income $ 57,736
$ 20,384
$ 277
$ —
$ 78,397
Total assets $ 4,439,694
$ 1,114,426
$ 2,812
—
$ 5,556,932
Capital expenditures $ 97,036
$ 22,087
$ —
—
$ 119,123


Six Months Ended
June 30, 2016	Electric			Gas			Other			Eliminations		Total
Three Months Ended
June 30, 2017															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	489,745		$	135,914		$	—		$	—	$	625,659		$	233,866		$	49,993		$	—		$	—	$	283,859
Cost of sales	155,789			41,338			—			—		197,127			70,146			13,854			—			—		84,000
Gross margin	333,956			94,576			—			—		428,532			163,720			36,139			—			—		199,859
Operating, general and administrative(1)	107,011			42,497			2,932			—		152,440			52,215			19,490			896			—		72,601
Property and other taxes	54,751			15,872			6			—		70,629			30,909			8,569			3			—		39,481
Depreciation and depletion	65,065			14,707			16			—		79,788			34,105			7,382			8			—		41,495
Operating income (loss)	107,129			21,500			(2,954		)	—		125,675			46,491			698			(907		)	—		46,282
Interest expense	(46,174		)	(3,769		)	(987		)	—		(50,930		)	(21,064		)	(1,500		)	(844		)	—		(23,408		)
Other income	1,154			580			2,563			—		4,297
Other (expense) income (1)															(954		)	(227		)	717			—		(464		)
Income tax (expense) benefit ~~(1)~~	(4,346		)	(1,743		)	2,483			—		(3,606		)	(523		)	817			(874		)	—		(580		)
Net income (1)	$	57,763		$	16,568		$	1,105		$	—	$	75,436
Net income (loss)															$	23,950		$	(212	)	$	(1,908	)	$	—	$	21,830
Total assets	$	4,221,293		$	1,080,065		$	6,248		$	—	$	5,307,606		$	4,439,694		$	1,114,426		$	2,812		$	—	$	5,556,932
Capital expenditures	$	99,563		$	21,683		$	—		$	—	$	121,246		$	55,995		$	11,609		$	—		$	—	$	67,604

______________

(1) We adopted ~~the provisions of~~ ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of2017-07 on January 1, ~~2016, which resulted in an increase in~~2018. As a result, we recorded the non-service cost component of net ~~income~~periodic benefit cost within other expense, net. We adopted this standard retrospectively and $1.9 million and $0.7 million, respectively, were reclassified from electric and gas operating, general and administrative expenses to other expense, net for the three months ended June 30, 2017, to conform to current period presentation.



Six Months Ended
June 30, 2018	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	448,097		$	155,222		$	—		$	—	$	603,319
Cost of sales	76,886			51,381			—			—		128,267
Gross margin	371,211			103,841			—			—		475,052
Operating, general and administrative	107,542			40,869			(232		)	—		148,179
Property and other taxes	67,373			18,478			4			—		85,855
Depreciation and depletion	72,292			14,988			16			—		87,296
Operating income	124,004			29,506			212			—		153,722
Interest expense	(39,838		)	(3,015		)	(3,314		)	—		(46,167		)
Other income (loss)	438			(83		)	(608		)	—		(253		)
Income tax expense	(3,147		)	(1,734		)	(135		)	—		(5,016		)
Net income (loss)	$	81,457		$	24,674		$	(3,845	)	$	—	$	102,286
Total assets	$	4,351,359		$	1,072,173		$	15,442		$	—	$	5,438,974
Capital expenditures	$	95,742		$	20,714		$	—		$	—	$	116,456



Six Months Ended
June 30, 2017	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	500,105		$	151,066		$	—		$	—	$	651,171
Cost of sales	155,531			48,286			—			—		203,817
Gross margin	344,574			102,780			—			—		447,354
Operating, general and administrative (1)	108,935			40,390			1,610			—		150,935
Property and other taxes	62,070			17,333			6			—		79,409
Depreciation and depletion	68,175			14,765			16			—		82,956
Operating income (loss)	105,394			30,292			(1,632		)	—		134,054
Interest expense	(42,101		)	(3,046		)	(1,661		)	—		(46,808		)
Other (expense) income (1)	(2,147		)	(728		)	1,283			—		(1,592		)
Income tax (expense) benefit	(3,410		)	(6,134		)	2,287			—		(7,257		)
Net income	$	57,736		$	20,384		$	277		$	—	$	78,397
Total assets	$	4,439,694		$	1,114,426		$	2,812		$	—	$	5,556,932
Capital expenditures	$	97,036		$	22,087		$	—		$	—	$	119,123

_____________

(1) We adopted ASU 2017-07 on January 1, 2018. As a result, we recorded the non-service cost component of net periodic benefit cost within other expense, net. We adopted this standard retrospectively and $3.8 million and $1.4 million, respectively, were reclassified from electric and gas operating, general and administrative expenses to other expense, net for the six months ended June 30, ~~2016 above.~~2017, to conform to current period presentation.

(10) Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:


	Three Months Ended		Three Months Ended
	June 30, 2017	June 30, 2016	June 30, 2018	June 30, 2017
Basic computation	48,450,639	48,308,656	49,869,176	48,450,639
Dilutive effect of:
Performance share awards (1)	130,772	76,877	175,369	130,772

Diluted computation	48,581,411	48,385,533	50,044,545	48,581,411


	Six Months Ended		Six Months Ended
	June 30, 2017	June 30, 2016	June 30, 2018	June 30, 2017
Basic computation	48,418,368	48,275,482	49,643,954	48,418,368
Dilutive effect of:
Performance share awards (1)	129,383	76,737	173,840	129,383

Diluted computation	48,547,751	48,352,219	49,817,794	48,547,751

_______

(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 10,090 and 10,116 for the three and six months ended June 30, 2016.

(11) Employee Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands):


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,367		$	2,941		$	100		$	116		$	2,684		$	2,367		$	87		$	100
Interest cost	6,388			6,539			178			196			6,102			6,388			142			178
Expected return on plan assets	(5,974		)	(7,043		)	(211		)	(260		)	(7,044		)	(5,974		)	(238		)	(211		)
Amortization of prior service cost	—			61			(470		)	(470		)	1			—			(470		)	(470		)
Recognized actuarial loss	1,944			2,478			81			71
Recognized actuarial loss (gain)													1,108			1,944			(20		)	81
Net Periodic Benefit Cost (Income)	$	4,725		$	4,976		$	(322	)	$	(347	)	$	2,851		$	4,725		$	(499	)	$	(322	)


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Components of Net Periodic Benefit Cost (Income)
Service cost	$	5,497		$	5,880		$	228		$	246		$	5,888		$	5,497		$	199		$	228
Interest cost	12,817			13,105			358			398			12,210			12,817			289			358
Expected return on plan assets	(11,982		)	(14,124		)	(424		)	(521		)	(14,104		)	(11,982		)	(477		)	(424		)
Amortization of prior service cost	2			123			(941		)	(941		)	2			2			(941		)	(941		)
Recognized actuarial loss	3,919			4,944			159			158
Recognized actuarial loss (gain)													2,180			3,919			(40		)	159
Net Periodic Benefit Cost (Income)	$	10,253		$	9,928		$	(620	)	$	(660	)	$	6,176		$	10,253		$	(970	)	$	(620	)

We adopted ASU 2017-07 on January 1, 2018. As a result, we recorded the non-service cost component of net periodic benefit cost within other expense, net. This standard requires retrospective adoptions, which resulted in a $2.6 million and $5.2 million reclassification from operating, general and administrative expenses to other expense, net for the three and six months ended June 30, 2017, to conform to current period presentation.

(12) Commitments and Contingencies



ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us and is estimated to range between ~~$27.9~~$26.7 million ~~to $32.6~~and $31.2 million. As of June 30, ~~2017,~~2018, we have a reserve of approximately ~~$30.6~~$29.6 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately ~~$23.8~~$22.8 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of June 30, ~~2017,~~2018, the reserve for remediation costs at this site is approximately ~~$10.4~~$9.3 million, and we estimate that approximately ~~$5.9~~$4.3 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana's state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. At MDEQ's direction, a soil vapor analysis plan for the two buildings located on the Helena site was submitted in January 2017. MDEQ reviewed the results of the analysis and indicated that work should be postponed until the winter of 2017-2018 to be integrated in an overall remediation plan for the Helena site. We expect to continue soil and groundwater sampling at the Helena site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In September 2017, we submitted a Draft Remedial Investigation Work Plan for the Helena site, based on the request of the MDEQ. Comments from the MDEQ are expected before the end of 2018.

An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. Analytical results from an October 2016 sampling exceeded the Montana Maximum Contaminant Level for benzene and/or total cyanide in certain monitoring wells. These results were forwarded to MVWQD which shared the same with the MDEQ. MDEQ requested that MVWQD file a formal complaint with MDEQ's Enforcement Division, which MVWQD filed in July 2017. This is expected to prompt MDEQ to reevaluate its position concerning listing the Missoula site on the State of Montana's superfund list. New landowners purchased a portion of the Missoula site using funding provided by a third party. The terms of the funding require the new landowners to address environmental issues. The new landowners contacted us and ~~have requested a meeting to address~~we addressed their immediate concerns. After researching historical ownership we have identified another potentially responsible party with whom we have initiated communications regarding the site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of ~~emissions of~~ greenhouse ~~gases~~gas (GHG) including, most significantly, carbon dioxide (CO₂). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions through regulations. EPA is currently reviewing its existing regulations as a result of an Executive Order issued by President Trump on March 28, 2017 (the Executive Order) instructing all federal agencies to review all regulations and other policies (specifically including the Clean Power Plan, , which is discussed in further detail below) that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest.

~~One of the regulations that the EPA~~The Clean Power Plan (CPP) was ~~instructed~~published in October 2015 and was intended to review under the Executive Order is the final standards of performance issued by EPA on August 3, 2015 which limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed natural gas combined cycle (NGCC) units. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit.

~~Another regulation that the EPA was instructed to review pursuant to the Executive Order is its final regulation establishing~~establish GHG performance standards for existing power plants under Clean Air Act Section 111(d)~~, which was published in October, 2015, and is referred to as the Clean Power Plan (CPP)~~. The CPP ~~establishes CO2~~established CO₂ emission performance standards for existing electric utility steam generating units and ~~NGCC~~natural gas combined cycle units.

~~Under~~ As a result of the Executive Order review, on October 10, 2017, the EPA proposed to repeal the CPP. Subsequently, the EPA issued an Advance Notice of Proposed Rulemaking, soliciting information on systems of emission reduction that comply with EPA’s interpretation of the Clean Air Act, for possible replacement of the CPP, ~~states may develop implementation plans for affected units to meet the individual state GHG emission reduction targets established~~which was published in the ~~CPP or may adopt a federal plan. The CPP may require reductions in CO~~Federal Register on December 28, 2017.₂ ~~emissions from~~

~~2012 emission levels of up to 38.4 percent in South Dakota and 47.4 percent in Montana by 2030. Neither South Dakota nor Montana has submitted implementation plans to date.~~

Following the issuance of the CPP ~~judicial appeals~~in October 2015, petitions for review were filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), including ~~an appeal~~a petition by ~~us filed on October 23, 2015.~~us. The United States Supreme Court (Supreme Court) issued a stay ~~of the CPP on February 9, 2016~~ pending resolution of the ~~appeals~~case by the D.C. ~~Circuit and possibly~~Circuit. Following issuance of the ~~Supreme Court. Oral argument on~~Executive Order, the ~~case was held in September 2016. In April 2017,~~EPA has requested the D.C. Circuit ~~granted the EPA's request~~ to hold the case in abeyance. The D.C. Circuit has incrementally granted those requests, most

recently in an order issued on June 26, 2018, holding the case in abeyance ~~pursuant~~for an additional 60 days. In that recent order, three of the nine D.C. Circuit Judges expressed they would not vote for further abeyances, absent good reason otherwise. On July 9, 2018, the EPA forwarded its proposed rule replacing the CPP to the ~~Executive Order, but only~~Office of Management and Budget (OMB) for ~~a period of sixty days.~~interagency review.

In addition, administrative requests for reconsideration of the CPP were filed with the EPA, including one filed by us in December 2015. We requested the EPA reconsider the CPP, in part, on the grounds that the CO₂ reductions in the CPP applicable to Montana were substantially greater than the reductions the EPA had originally proposed. The EPA denied the petition for reconsideration on January 11, 2017, and we appealed that denial to the D.C. Circuit on March 13, 2017. The EPA has also requested that this case be held in abeyance. ~~No action has been taken by the D.C. Circuit in this case.~~

~~There is no certainty as to~~We cannot predict what, if any, action the D.C. Circuit may take in either of these two cases, ~~before~~particularly in light of the ~~EPA takes action~~EPA’s proposal to ~~address~~repeal the CPP.

If the CPP is not repealed, survives ~~the Executive Order,~~ the legal challenges described above, and is implemented as written, or if a replacement to the CPP is adopted with similar requirements, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are not recovered through regulated rates. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from ~~the CPP~~any GHG regulations that, in our view, disproportionately impacts customers in our region. We cannot predict the ultimate outcome of these matters or what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the CO₂ emission performance standards in the CPP, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

~~In addition, future~~Future additional environmental requirements ~~to reduce GHG emissions~~ could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities.

~~Water Intakes and Discharges~~ - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the United States Court of Appeals for the Second Circuit.

In November 2015, the EPA published final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. The rule became effective in January 2016. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations. Challenges to the final rule have been filed in the United States Court of Appeals for the Fifth Circuit, asserting that the EPA underestimated compliance costs. It is too early to determine whether the impacts of these rules will be material.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership.

In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the D.C. Circuit, and the D.C. Circuit remanded, without vacatur, the MATS rule to the EPA, leaving the rule in place. In April 2016, the EPA published its final supplemental finding that it is "appropriate and necessary" to regulate coal and oil-fired units under Section 112 of the Clean Air Act. Although industry and trade associations have filed a lawsuit in the D.C. Circuit challenging the EPA's supplemental finding and the D.C. Circuit recently delayed oral argument in the case at the request of the Trump administration, installation or upgrading of relevant environmental controls at our affected plants is complete and we are controlling emissions of mercury under the state and Federal MATS rules.

~~In October 2013, the Supreme Court denied certiorari in~~ ~~Luminant Generation Co v. EPA~~, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in 'Class I' areas.

In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. The plan does not require Colstrip Units 3 and 4 to improve removal efficiency for pollutants that contribute to regional haze. In November 2012, PPL Montana (now Talen Montana, LLC) (Talen), the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center (MEIC), and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). MEIC and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action.

On January 10, 2017, the EPA published amendments to the requirements under the Clean Air Act for state plans for protection of visibility. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. Therefore, by 2021, Montana, or EPA, must develop a revised plan that demonstrates reasonable progress toward eliminating man-made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. OnIn March ~~13,~~ 2017, we filed a Petition for Review of these amendments with the D.C. ~~Circuit. On March 15, 2017, our petition~~Circuit, which was consolidated with other petitions challenging the final rule. While the EPA has not responded to our petition, on January 19, 2018, EPA advised the D.C. Circuit that it intended to initiate rulemaking to revisit the amendment, and asked that the case be held in abeyance. On January 30, 2018, the D.C. Circuit granted the EPA's request to hold the case in abeyance pending further order of the court. On April 27, 2018, the EPA filed a status report with the D.C. Circuit advising it that EPA has continued to assess the rule and expressing the EPA’s belief that the case should remain in abeyance while its administrative proceeding continues.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed.

Regarding the CPP, as discussed above, we cannot predict the impact of the CPP on ~~NorthWestern~~us until there is a definitive judicial decision or administrative action by the EPA ~~to withdraw~~repealing or significantly ~~change~~changing the CPP.

~~Compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in January 2016, did not have a significant impact at any of our jointly owned facilities.~~

~~North Dakota~~. The North Dakota Regional Haze state implementation plan requires the Coyote generating facility, in which we have 10% ownership, to reduce its nitrogen oxide (NOx) emissions by July 2018. In 2016, Coyote completed installation of control equipment to maintain compliance with the lower NOx emissions of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown. The cost of the control equipment was not significant.

~~Montana.~~Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's coal combustion residual rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90.0 million (our share is 30%) over the remaining life of the facility.

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

~~Billings, Montana Refinery Outage Claim~~

In August 2014, we received a letter from the ExxonMobil refinery in Billings, Montana claiming that it had sustained approximately $48.5 million in damages as a result of a January 2014 electrical outage. In December 2015, ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $108.0 million. We dispute ExxonMobil’s claims and intend to vigorously defend this lawsuit. We have reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also have brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they are responsible in whole or in part for the outages. We are not currently able to predict an outcome or estimate the amount or range of loss that would be associated with an adverse result.

Pacific Northwest Solar Litigation

Pacific Northwest Solar, LLC (PNWS) is ~~an Oregon~~a solar QF developer ~~with which we~~seeking to construct small solar facilities in Montana. We began negotiating in early 2016 to purchase ~~capacity and energy at~~the output from these facilities pursuant to our ~~avoided cost under the~~standard QF-1 ~~option 1(a) tariff standard rates in accordance with PURPA as implemented by the FERC and the MPSC.~~Tariff, which is applicable to projects greater than 100 kW, but no larger than 3 MW.

On June 16, 2016, however, the MPSC ~~entered a Notice of Commission Action (MPSC Notice) suspending~~suspended the availability of the QF-1 ~~option 1(a)~~Tariff standard rates for solar projects, ~~greater than 100 kW,~~ which included the various projects proposed by PNWS. The MPSC exempted from the suspension any ~~contracts with solar QFs greater than 100 kW, but no larger than 3 MW, at the standard tariff rate, if prior to the date of the MPSC Notice, the~~projects for which a QF had submitted a signed power purchase agreement and had executed an interconnection agreement. Because PNWS had not ~~obtained~~executed interconnection agreements for any of its projects as of June 16, 2016, ~~and, based on~~it did not qualify for the ~~MPSC Notice and subsequent July 25, 2016 Order 7500 of like effect from the MPSC, we discontinued further negotiations with PNWS.~~exemption.

On August 30, 2016, PNWS sent us a letter demanding that we enter into power purchase agreements for 21 solar projects and threatening to sue us for $106 million if we did not accede to its demand. We declined to do so, and onIn November ~~16,~~ 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and other relief, including a judicial declaration that some or all of ~~the~~21 proposed power purchase agreements were in effect. We removed the state lawsuit to the United States District Court for the District of ~~Montana, which then stayed the case until September 29, 2017, so that~~Montana.

PNWS also requested the MPSC ~~could consider related issues that might bear on~~to exempt its projects from the ~~issues raised~~tariff suspension. We joined in ~~PNWS's lawsuit.~~

~~On July 19, 2017, we and PNWS entered into a partial settlement agreement that resolved some but not all of PNWS' litigation claims. In return for our support of PNWS' application~~PNWS’s request to the MPSC for ~~approval~~relief on four of the projects. The MPSC did not grant PNWS or us the relief requested.

On August 14, 2017, PNWS amended its ~~first four solar projects, PNWS agreed~~original complaint to ~~drop its damage claims~~seek enforcement and/or damages related to four of the ~~other 17 projects. If~~21 power purchase agreements.

Currently pending before the ~~MPSC approves the four projects, PNWS will also drop~~United States District Court are our motion to dismiss, our motion for partial summary judgment, and PNWS’s motion for summary judgment on its ~~damage claims related to~~request for declaratory relief regarding those four ~~projects. If the MPSC does not approve the four projects, PNWS will be able~~power purchase agreements.

~~to pursue all of its claims related to those four projects. PNWS can continue to seek (and we can continue to oppose) regulatory approval of~~We dispute the remaining ~~projects, but PNWS will not pursue monetary damage~~ claims ~~related to those projects.~~

~~We dispute all of the claims that PNWS has made~~ in ~~its~~PNWS’ lawsuit and intend to vigorously defend those ~~that have not been resolved by the partial settlement.~~claims. This matter is in the initial stages, and we cannot predict an outcome or estimate the am~~ount~~amount or range of loss that would ~~be associated with~~result from an adverse ~~result on~~outcome in the remaining claims.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State's Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen Montana, LLC (Talen) as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the ~~Missouri-Madison~~Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

Prior to our acquisition of the facilities, Talen litigated this issue against the State in State District Court, the Montana Supreme Court and in the United States Supreme Court. In August 2007, the State District Court determined that the 10 hydroelectric facilities were located on riversThe litigation has a long prior history, which ~~were navigable and that the State held title to the riverbeds. Subsequently, in June 2008, the State District Court awarded the State compensation~~culminated with respect to all 10 facilities of approximately $34 million for the 2000-2006 period and approximately $6 million for 2007. The District Court deferred the determination of compensation for 2008 and future years to the Montana State Land Board.

~~Talen appealed the issue of navigability to the Montana Supreme Court, which in March 2010 affirmed the State District Court decision. In June 2011,~~a 2012 decision by the United States Supreme Court ~~granted Talen's petition to review~~holding that the Montana Supreme Court ~~decision. The United States Supreme Court issued an opinion~~erred in ~~February 2012, overturning the Montana Supreme Court and holding that the Montana courts erred first by~~ not considering ~~the navigability of the rivers on~~ a segment-by-segment ~~basis~~approach to determine navigability and ~~second in~~ relying on present day recreational use of the rivers. ~~The United States Supreme Court~~It also ~~considered the navigability of~~held that what it referred to as the Great Falls Reach ~~and concluded, at~~"at least from the head of the first waterfall to the foot of the ~~last, that the Great Falls Reach~~last" was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion.

Following the 2012 remand, the case laid dormant for four years until the ~~State~~State's Complaint was filed ~~its complaint on remand~~ with the State District Court. The complaint on remand renews all of the State’s claims that the rivers on which the 10 hydroelectric facilities are located are navigable (including the Great Falls Reach), that because they were navigable the riverbeds became State lands upon Montana’s statehood in 1889 and that the State is entitled to rent for their use. The State’s complaint on remand does not claim any specific rental amount. Pursuant to the terms of our acquisition of the hydroelectric facilities, Talen and NorthWestern will share jointly the expense of this litigation, and Talen is responsible for any rents applicable to the periods of time prior to the acquisition (i.e., before November 18, 2014), while we are responsible for periods thereafter.

On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court),. The State filed a motion to remand and ~~Talen consented to our removal. On April 27, 2016,~~following briefing and argument, on October 10, 2017, the Federal District Court Judge entered an order denying the State’s motion. As the State's Complaint included a claim that the State owned the riverbeds in the Great Falls Reach, on October 16, 2017, we and Talen renewed our earlier filed motions ~~with the Federal District Court~~ seeking to dismiss the portion of the ~~litigation dealing with~~State's Complaint concerning the Great Falls Reach in light of the United States Supreme Court’s ~~decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment.~~

~~On May 19, 2016, the State asked the Federal District Court to remand the case back to the State District Court and to dismiss Talen’s consent to removal.~~decision. The parties briefed the remand issue and oral argument was held before the Magistrate on January 17, 2017. On January 23, 2017 the Magistrate issued his Findings and Recommendation. The Magistrate recommended the Federal District Court remand the case to State District Court. On February 20, 2017, we filed objections to the Magistrate’s Findings and Recommendation, arguing that the Federal District Court should retain jurisdiction. The following day Talen filed its objections to the Federal Magistrate’s Findings and Recommendation, which we joined in on February 23, 2017. On March 21, 2017, the State filed its response to the objections. On March 24, 2017, in separate motions, both we and Talen filed motions asking the Federal District Court to hear oral argument on our respective objections. On July 10, 2017, the Federal District Court granted the motions for oral argument. Oral argument will be held before the U.S. District Judge on August 16, 2017. Our objections to the Magistrate's Findings and Recommendation along with Talen's and our motions to dismiss ~~the State's claim regarding the Great Falls Reach remain pending. The Federal District Court will not address the motions to~~have been fully briefed and argued and are awaiting decision.

~~dismiss unless it retains jurisdiction. If the case is remanded to State District Court, we will file new motions to dismiss regarding the Great Falls Reach.~~

We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If the Federal District Court ~~(or the State District Court if the case is remanded to it)~~ determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately ~~$7.0~~$7 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Wilde Litigation

On October 10, 2017, Martin Wilde, a Montana resident and wind developer, and three entities with which he is affiliated, commenced a lawsuit against the MPSC, each individual commissioner of the MPSC (in each of their official and individual capacities), and NorthWestern in the Montana Eighth Judicial District Court (Eighth District Court). The plaintiffs allege that the MPSC collaborated with NorthWestern to set discriminatory rates and contract durations for QF developers. The plaintiffs seek power purchase agreements at $45.19 per megawatt hour for a 25-year term or, as an alternative remedy to the alleged discrimination, a reduction in NorthWestern’s rates by $17.03 per megawatt hour. The plaintiffs also seek compensatory damages of not less than $4.8 million, various forms of declaratory relief, injunctive relief, unspecified damages, and punitive damages.

On October 20, 2017, the Eighth District Court conducted a hearing on the plaintiffs' application for a preliminary injunction to stop the defendants from the alleged ongoing discrimination that harms development of renewable energy in Montana. At the hearing’s conclusion, the court did not rule on the requested injunction but orally ordered post-hearing briefs and set deadlines for answers and dispositive motions. On November 11, 2017, Mr. Wilde died in a farming accident, and, at plaintiffs’ request, the Eighth District Court stayed the proceeding through May 11, 2018. On May 10, 2018, the plaintiffs requested a status conference to determine a schedule and next steps for this litigation. The Court has not set a status conference.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately ~~709,600~~718,300 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017.

As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for ~~2017~~2018 and ~~2016.~~2017.



HOW WE PERFORMED AGAINST OUR SECOND QUARTER ~~2016~~2017 RESULTS

Quarter-over-Quarter Change

Gross Margin by Segment⁽¹⁾

Electric

$(12.4)M

(7.0)%

$26.3M

16.1%

Natural Gas

$0.9M

2.6%

$3.4M

9.4%

Operating Income

$(20.0)M

(31.5)%

$22.9M

49.5%

Net Income

$(13.7)M

(38.6)%

$22.0M

100.6%

EPS (Diluted)

$(0.29)

(39.7)%

Diluted Earnings per Average Common Share

$0.43

97.7%

(1) Non-GAAP financial measure. See ~~"non-GAAP~~"Non-GAAP Financial Measure" below.



~~SIGNIFICANT DEVELOPMENTS IN Q2 2017~~



Ÿ	~~A decrease~~For the second quarter of 2018, we had an increase in net income of ~~$13.7~~approximately $22 million, primarily due to a gain related to the ~~recognition in 2016~~adjustment of ~~$14.2 million of deferred revenue as~~our QF liability and favorable weather, and to a ~~result of a MPSC final order in our tracker filings, lower retail~~lesser extent increased demand for electric ~~volumes and higher operating expenses in 2017.~~	transmission.

Following is a brief overview of significant items for ~~2017.~~2018.



SIGNIFICANT TRENDS AND REGULATION

~~Montana Natural Gas General Rate Filing~~Tax Cuts and Jobs Act

In ~~June~~December 2017, the Tax Cuts and Jobs Act was signed into law, which enacts significant changes to U.S. tax and related laws. The primary impact to us is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In each of our jurisdictions, we ~~reached a settlement agreement with intervenors in our natural gas rate case. This settlement included an overall increase in delivery services~~expect the Tax Cuts and ~~production charges of approximately $5.7 million, based upon a 6.96 percent rate of return (9.55 percent return on equity, 4.67 percent cost of debt~~Jobs Act related credits to continue and ~~53.2 percent debt~~be subject to rate base). In our initial filing in September 2016, we requested an annual increase to natural gas rates of approximately $10.9 million, with rebuttal testimony filed in April 2017 supporting a revised requested annual increase to rates of approximately $9.4 million. The natural gas production part of this filing includes a request for cost-recovery and permanent inclusion intrue-up until base rates ~~of fields acquired~~are reset in ~~August 2012 and December 2013 in northern Montana's Bear Paw Basin. Actual production costs are currently recovered in customer rates on an interim basis through~~a general rate case filing or agreement is reached with our ~~supply tracker.~~

~~The MPSC held a work session on July 20, 2017, and voted~~state regulatory commissions as to draft an order accepting the settlement with modifications. We estimate that these modifications lower the increase in delivery services and production charges to approximately $5.1 million. Due to the MPSC's modification of the settlement, any of the parties may elect to withdraw and request a new hearing. We will evaluatehow the impact of ~~these modifications upon receipt of a final order, which we expect in August 2017.~~the Tax Cuts and Job Act will be resolved.

~~QF Decision~~

~~Under the PURPA, electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. The MPSC held a work session in~~As of June ~~2017 to discuss our application for approval~~30, 2018, we have deferred revenue of a revised tariff for standard rates for small QFs. In July 2017, the MPSC issued an order establishing a maximum 10-year contract length with a rate adjustment after the first five years, and approving rates that do not include costsapproximately $13.5 million associated with the ~~risk~~impacts of ~~potential future carbon dioxide emissions regulations. We expect this will~~the Tax Cuts and Jobs Act. For purposes of the filings discussed below, we calculated the customer benefit using two alternate methods based on current and historic test periods. The revenue deferral is based upon our 2018 estimated impact of Tax Cuts and Jobs Act of approximately $18 million to $23 million and is offset by a corresponding reduction in income tax expense. Application of the historic method would result in ~~substantially lower rates for these contracts. In this same order,~~customer refunds that exceed the ~~MPSC indicated they will apply the 10-year contract term~~reduction in our 2018 taxes, which would be an additional reduction in pretax earnings and cash flows ranging from approximately $5 million to us for future electric supply resource transactions. We have significant generation capacity deficits and negative reserve margins. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. Our 2016 resource plan identified price and reliability risks to our customers of solely relying upon market purchases to address these needs. We are evaluating the impact of this decision and have suspended our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana.$10 million.

We cannot predict how each jurisdiction may calculate the amount of credits due to customers. If any of our regulatory jurisdictions determines the credits due to customers are higher than the expected reduction to income tax expense, this would result in an adverse impact to results of operations and cash flows.

Cost Recovery Mechanisms

Montana House Bill 193 / Electric ~~and Natural Gas~~ Tracker ~~Filings~~

~~House Bill 193~~ - In April 2017, the Montana legislature passed HB 193, ~~repealing~~amending the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. ~~In May 2017,~~The revised statute gives the MPSC ~~issued a NCA initiating~~discretion whether to approve an electric supply cost adjustment mechanism. The MPSC initiated a process to develop a replacement electric ~~tracker mechanism. We filed a motion for reconsideration of the May 2017 NCA. On July 7, 2017, the MPSC issued an additional NCA addressing the arguments~~supply cost adjustment mechanism, and in our motion for reconsideration and identifying three replacement mechanism alternatives for consideration, and establishing a timeline. Two of the replacement mechanism alternatives identified include updating the fixed rate portion of the recovery of our electric supply assets in addition to the variable costs that were recovered through the prior electric tracker. This would be accomplished through an electric supply revenue requirements filing to be made by us by September 30, 2017. The July 2017 NCA also raises questions regarding our earnings as compared with our authorized rate of return for 2016 for electric supply. As noted below in the hydro compliance filing discussion, our 2016 MPSC annual report indicates we earned less than our authorized rate of return with electric delivery service and supply combined. The NCA established a timeline for the parties to provide commentsresponse, in July ~~2017, on the issue of whether the MPSC should require a September 2017 filing, and we are awaiting a further decision.~~

~~On July 14,~~ 2017, we filed a proposed electric ~~PCCAM with~~PCCAM. In December 2017, after the ~~MPSC.~~ intervenors filed testimony, the MPSC issued a Notice of Additional Issues stating that the range of options proposed by the parties was not sufficient and directing parties to consider alternatives incorporating risk-sharing features of other utilities in the region.

We ~~believe~~filed testimony in February 2018, responsive to both the ~~PCCAM filing is consistent with~~intervenors' testimony and the MPSC's ~~advocacy for HB 193,~~Notice of Additional Issues addressing alternative risk-sharing mechanisms. Intervenors filed testimony on the ~~MPSC's May~~Notice of Additional Issues in March 2018. The MPSC held a hearing during the second quarter of 2018, and ~~July 2017 NCAs and~~we expect a decision in the ~~MDU Montana adjustment~~matter no later than the fourth quarter of 2018. If the MPSC approves a new mechanism, ~~that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how~~ the MPSC may apply the ~~statute in establishing a revised mechanism. We expect application of the new~~ mechanism to variable costs ~~to be~~on a retroactive basis to the effective date of HB ~~193.~~

193 (July 1, 2017).



RESULTS OF OPERATIONS

Our consolidated results include the results of our ~~reportable~~divisions and subsidiaries constituting each of our business ~~segments, which are primarily engaged in the electric and natural gas business.~~segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Gross Margin ~~(Revenues~~as Revenues less Cost of ~~Sales) is~~Sales as presented in our Condensed Consolidated Statements of Income.

Management believes that Gross Margin (revenues less cost of sales) provides a ~~non-GAAP~~useful measure for investors and other financial ~~measure due~~statement users to analyze our financial performance in that it excludes the ~~exclusion of depreciation~~effect on total revenues caused by volatility in energy costs and ~~depletion from the measure. The presentation of Gross Margin~~associated regulatory mechanisms. This information is intended to ~~supplement investors’~~enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers, and as a result do not typically impact operating ~~performance.~~or net income. In addition, Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating ~~costs.~~costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Gross Margin measure may not be comparable to that of other ~~companies’ Gross Margin measure. Furthermore,~~companies' presentations or more useful than the GAAP information provided elsewhere in this ~~measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.~~report.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted ~~to a lesser extent~~ by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, ~~2017~~2018 Compared with the Three Months Ended June 30, ~~2016~~2017

Three Months Ended June 30,
2017 2016 Change % Change
(dollars in millions)
Operating Revenues
Electric $ 233.9
$ 248.4
$ (14.5 ) (5.8 )%
Natural Gas 50.0
44.7
5.3
11.9
Total Operating Revenues $ 283.9
$ 293.1
$ (9.2 ) (3.1 )%



	Electric				Natural Gas				Total
	2018		2017		2018		2017		2018		2017
	(dollars in millions)
Reconciliation of gross margin to operating revenue:
Operating Revenues	$	209.7	$	233.9	$	52.1	$	50.0	$	261.8	$	283.9
Cost of Sales	19.6		70.1		12.6		13.9		32.2		84.0
Gross Margin⁽¹⁾	$	190.1	$	163.8	$	39.5	$	36.1	$	229.6	$	199.9

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


	Three Months Ended June 30,									Three Months Ended June 30,
	2017		2016		Change			% Change		2018		2017		Change		% Change
	(dollars in millions)									(dollars in millions)
Cost of Sales
Gross Margin
Electric	$	70.1	$	72.2	$	(2.1	)	(2.9	)%	$	190.1	$	163.8	$	26.3	16.1	%
Natural Gas	13.9		9.5		4.4			46.3		39.5		36.1		3.4		9.4
Total Cost of Sales	$	84.0	$	81.7	$	2.3		2.8	%
Total Gross Margin⁽¹⁾										$	229.6	$	199.9	$	29.7	14.9	%

Three Months Ended June 30,
2017 2016 Change % Change
(dollars in millions)
Gross Margin
Electric $ 163.8
$ 176.2
$ (12.4 ) (7.0 )%
Natural Gas 36.1
35.2
0.9
2.6
Total Gross Margin $ 199.9
$ 211.4
$ (11.5 ) (5.4 )%
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Primary components of the change in gross margin, defined as revenues less cost of sales, include the following:

Gross Margin 2017 vs. 2016
(in millions)
Gross Margin Items Impacting Net Income
2016 Lost revenue adjustment mechanism $ (14.2 )
Electric retail volumes (1.4 )
MPSC 2016 disallowance (adjustment) (0.8 )
Natural gas production (0.1 )
Natural gas retail volumes 1.3
Electric transmission 0.4
Electric QF adjustment 0.4
Other (0.7 )
Change in Gross Margin Impacting Net Income (15.1 )

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers 3.2
Gas production gathering fees 0.4
Change in Items Offset Within Net Income 3.6
Decrease in Gross Margin $ (11.5 )



	Gross Margin 2018 vs. 2017
	(in millions)
Gross Margin Items Impacting Net Income
Electric QF liability adjustment	$	25.1
Electric and natural gas retail volumes	4.0
Electric transmission	1.4
Montana natural gas and production rates	0.3
Other	1.3
Change in Gross Margin Impacting Net Income	32.1

Gross Margin Items Offset in Operating and Income Tax Expense
Tax Cuts and Jobs Act deferral	(6.2		)
Natural gas production gathering fees	(0.4		)
Property taxes recovered in trackers	3.5
Production tax credits flowed-through trackers	0.7
Change in Items Offset Within Net Income	(2.4		)
Increase in Gross Margin⁽¹⁾	$	29.7

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Consolidated gross margin for items impacting net income ~~decreased $15.1~~increased $32.1 million due to the ~~following:~~following items:

~~The inclusion in our 2016 results of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings regarding prior period lost revenues;~~

A ~~decrease~~reduction in the electric ~~retail volumes~~QF liability due to the combination of (i) a periodic adjustment of the liability for price escalation, which was less than modeled resulting in a liability reduction of approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million in lower QF related supply costs due primarily to ~~milder spring weather partly offset by customer growth;~~

~~An adjustment in 2016 in~~outages at two facilities. Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the ~~disallowance of modeling costs based on an~~ MPSC ~~final order;~~ and

Lower gas production margin due primarily to a $0.4 million reduction in interim rates of the production assets recovered through the natural gas tracker, partly offset by a $0.3 million increase in overhead fees.

~~These decreases were partly offset by:~~

other parties;

An increase in electric and natural gas retail volumes due primarily to ~~colder spring~~favorable weather ~~in our Montana and South Dakota jurisdictions~~ and customer growth;

Higher demand to transmit energy across our transmission lines due to market conditions and pricing; and

~~A decrease~~An increase in ~~QF related supply costs based on actual QF pricing and output.~~our Montana gas rates effective September 1, 2017.

The change in consolidated gross margin also includes the following items that had no impact on net income:

A decrease due to the deferral of revenue as a result of the Tax Cuts and Job Act, offset by a decrease in income tax expense;

A decrease in natural gas production gathering fees, offset by reduced operating expenses;

An increase in revenues for property taxes included in trackers, is offset by increased property tax ~~expense with no impact to net income;~~expense; and

An increase in ~~natural gas~~revenue due to the decrease in production ~~gathering fees is~~tax credit benefits passed through to customers in our tracker mechanisms, which are offset by ~~an increase in operating expenses.~~increased income tax expense.


	Three Months Ended June 30,								Three Months Ended June 30,
	2017		2016		Change		% Change		2018		2017		Change		% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	75.2	$	72.6	$	2.6	3.6	%	$	73.8	$	72.6	$	1.2	1.7	%
Property and other taxes	39.5		35.2		4.3		12.2		43.0		39.5		3.5		8.9
Depreciation and depletion	41.5		39.9		1.6		4.0		43.5		41.5		2.0		4.8
	$	156.2	$	147.7	$	8.5	5.8	%	$	160.3	$	153.6	$	6.7	4.4	%

Consolidated operating, general and administrative expenses were ~~$75.2~~$73.8 million for the three months ended June 30, ~~2017,~~2018, as compared with $72.6 million for the three months ended June 30, ~~2016.~~2017. Primary components of the change include the following:


	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2017 vs. 2016			2018 vs. 2017
	(in millions)			(in millions)
Employee benefits				$	2.7
Maintenance Costs				(2.0		)
Labor	$	0.9		(1.0		)
Bad debt expense	0.6
Maintenance costs	0.5
Non-employee directors deferred compensation	0.4
Distribution System Infrastructure Project expenses				(0.7		)
Natural gas production gathering expense	0.4			(0.4		)
Other	(0.2		)	(0.5		)
Operating, General & Administrative Expenses impacting Net Income				(1.9		)

Operating, General & Administrative Expenses Offset in Other Income
Pension and other postretirement benefits				2.6
Non-employee directors deferred compensation				0.5
Change in Items Offset Within Other Income				3.1
Increase in Operating, General & Administrative Expenses	$	2.6		$	1.2

~~The increase in~~Consolidated operating, general and administrative expenses ~~is primarily~~for items impacting net income decreased $1.9 million due to the following:

~~Increased~~An increase in employee benefit costs primarily due to higher medical and pension expense;

Lower maintenance costs at generation facilities;

Decreased labor costs due primarily to ~~compensation increases and~~ more time being spent by employees on capital rather than maintenance projects (which are expensed) ~~rather than capital projects;~~;

~~Higher bad debt~~Lower Distribution System Infrastructure Project related expenses, which concluded in 2017; and

Lower gas production gathering expense (offset by lower gathering fees discussed above).

The change in consolidated operating, general and administrative expenses also includes the following items that are offset in other income (expense) below and had no impact on net income:

The regulatory treatment of the non-service cost components of pension and postretirement benefit expense;

~~Higher maintenance costs at our Dave Gates Generating Station~~ and ~~Colstrip Unit 4;~~

The change in value of non-employee directors deferred compensation due to changes in our stock ~~price (offset by changes in other income with no impact on net income); and~~

~~An increase in natural gas production gathering expense (offset by higher gathering fees discussed above).~~price.

Property and other taxes were ~~$39.5~~$43.0 million for the three months ended June 30, ~~2017,~~2018, as compared with ~~$35.2~~$39.5 million in the same period of ~~2016.~~2017. This increase was primarily due to plant additions and higher estimated property valuations in Montana. We estimate property taxes throughout each year, and update based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and adjust our rates to recover ~~these amounts. Our Montana property tax tracker mechanism currently allows for~~ the ~~recovery of~~

~~approximately 60%~~increase between rate cases less the amount allocated to FERC-jurisdictional customers and net of the ~~estimated increase in our state and local taxes and fees (primarily property taxes) as compared with the related amount included in rates during our last general rate case.~~associated income tax benefit.

Depreciation and depletion expense was ~~$41.5~~$43.5 million for the three months ended June 30, ~~2017,~~2018, as compared with ~~$39.9~~$41.5 million in the same period of ~~2016.~~2017. This increase was primarily due to plant additions.

Consolidated operating income for the three months ended June 30, ~~2017~~2018 was ~~$43.7~~$69.2 million as compared with ~~$63.7~~$46.3 million in the same period of ~~2016.~~2017. This ~~decrease~~increase was primarily due to the ~~decrease in gross margin driven~~adjustment of our QF liability and favorable weather, partly offset by the ~~recognition~~overall increase in ~~2016 of deferred revenue~~operating expenses, as ~~a result of a MPSC final order, lower electric retail volumes and higher property taxes.~~discussed above.

Consolidated interest expense for the three months ended June 30, ~~2017~~2018 was ~~$23.4~~$23.2 million, as compared with ~~$26.4~~$23.4 million in the same period of ~~2016. This~~2017, with a decrease ~~was primarily due to $2.9 million of interest associated with~~from the ~~2016 MPSC~~

~~disallowance along with the debt~~ refinancing of ~~the Pollution Control Revenue Refunding Bonds during the third quarter of 2016.~~debt in 2017 partly offset by rising interest rates.

Consolidated other income was $0.9 million for the three months ended June 30, ~~2017, was $2.1 million,~~2018 as compared ~~with $1.2~~to consolidated other expense of $0.5 million induring the same period of ~~2016.~~2017. This ~~increase was primarily due to higher capitalization of allowance for funds used during construction (AFUDC)~~improvement includes a decrease in other pension expense and ~~a $0.4 million~~an increase in the value of deferred shares held in trust for non-employee directors deferred compensation, ~~(which, as discussed above, is~~both of which are offset ~~by a corresponding decrease to~~in operating, general, and administrative ~~expenses)~~expenses with no impact to net income. These improvements were partly offset by lower capitalization of Allowance for Funds Used During Construction (AFUDC).

Consolidated income tax expense for the three months ended June 30, ~~2017~~2018 was ~~$0.6~~$3.1 million as compared with ~~$2.9~~$0.6 million in the same period of ~~2016.~~2017. Our effective tax rate for the three months ended June 30, ~~2017~~2018 was ~~2.6%~~6.6% as compared with ~~7.7%~~2.6% for the same period of ~~2016.~~2017. We expect our ~~2017~~2018 effective tax rate to range between 7%0% - ~~11%~~5%.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):


	Three Months Ended June 30,										Three Months Ended June 30,
	2017					2016					2018					2017
Income Before Income Taxes	$	22.4				$	38.5				$	46.9				$	22.4

Income tax calculated at 35% federal statutory rate	7.8			35.0	%	13.5			35.0	%
Income tax calculated at federal statutory rate											9.8			21.0	%	7.8			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(0.5		)	(2.2	)	(1.0		)	(2.7	)	0.8			1.7		(0.5		)	(2.2	)
Flow-through repairs deductions	(4.7		)	(21.2	)	(7.0		)	(18.1	)	(4.1		)	(8.7	)	(4.7		)	(21.2	)
Production tax credits	(1.4		)	(6.5	)	(2.3		)	(6.0	)	(2.5		)	(5.5	)	(1.4		)	(6.5	)
Plant and depreciation of flow through items	(0.7		)	(3.1	)	(0.3		)	(0.6	)	(0.6		)	(1.2	)	(0.7		)	(3.1	)
Prior year permanent return to accrual adjustments	—			—		(0.1		)	(0.3	)
Other, net	0.1			0.6		0.1			0.4		(0.3		)	(0.7	)	0.1			0.6
	(7.2		)	(32.4	)	(10.6		)	(27.3	)	(6.7		)	(14.4	)	(7.2		)	(32.4	)

Income Tax Expense	$	0.6		2.6	%	$	2.9		7.7	%	$	3.1		6.6	%	$	0.6		2.6	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate ~~of 35%~~ primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

Consolidated net income for the three months ended June 30, ~~2017~~2018 was ~~$21.8~~$43.8 million as compared with ~~$35.6~~$21.8 million for the same period in ~~2016.~~2017. This ~~decrease~~increase was primarily due to a gain related to the ~~recognition in 2016~~adjustment of ~~deferred revenue as a result of a MPSC final order in~~ our ~~tracker filings, lower electric retail volumes~~QF liability and ~~higher operating expenses as discussed above,~~favorable weather, partly offset by ~~lower interest~~the overall increase in operating expenses and higher income tax ~~expense.~~

expense, as discussed above.

Six Months Ended June 30, ~~2017~~2018 Compared with the Six Months Ended June 30, ~~2016~~2017

Six Months Ended June 30,
2017 2016 Change % Change
(dollars in millions)
Operating Revenues
Electric $ 500.1
$ 489.7
$ 10.4
2.1 %
Natural Gas 151.1
135.9
15.2
11.2
Total Operating Revenues $ 651.2
$ 625.6
$ 25.6
4.1 %

Six Months Ended June 30,
2017 2016 Change % Change
(dollars in millions)
Cost of Sales
Electric $ 155.5
$ 155.8
$ (0.3 ) (0.2 )%
Natural Gas 48.3
41.3
7.0
16.9
Total Cost of Sales $ 203.8
$ 197.1
$ 6.7
3.4 %



	Electric				Natural Gas				Total
	2018		2017		2018		2017		2018		2017
	(dollars in millions)
Reconciliation of gross margin to operating revenue:
Operating Revenues	$	448.1	$	500.1	$	155.2	$	151.1	$	603.3	$	651.2
Cost of Sales	76.9		155.5		51.4		48.3		128.3		203.8
Gross Margin⁽¹⁾	$	371.2	$	344.6	$	103.8	$	102.8	$	475.0	$	447.4

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


	Six Months Ended June 30,								Six Months Ended June 30,
	2017		2016		Change		% Change		2018		2017		Change		% Change
	(dollars in millions)								(dollars in millions)
Gross Margin
Electric	$	344.6	$	333.9	$	10.7	3.2	%	$	371.2	$	344.6	$	26.6	7.7	%
Natural Gas	102.8		94.6		8.2		8.7		103.8		102.8		1.0		1.0
Total Gross Margin(1)	$	447.4	$	428.5	$	18.9	4.4	%	$	475.0	$	447.4	$	27.6	6.2	%

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Primary components of the change in gross margin include the following:


	Gross Margin 2017 vs. 2016			Gross Margin 2018 vs. 2017
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
MPSC 2016 disallowance	$	9.5
Natural gas retail volumes	7.3
Electric retail volumes	7.2
South Dakota electric rate increase	1.2
Electric QF adjustment	0.4
Electric QF liability adjustment				$	25.1
Electric and natural gas retail volumes				5.5
Electric transmission	0.2			2.9
2016 Lost revenue adjustment mechanism	(14.2		)
Natural gas production	(0.7		)
Montana natural gas and production rates				2.2
Other	1.3			0.5
Change in Gross Margin Impacting Net Income	12.2			36.2

Gross Margin Items Offset in Operating Expenses
Tax Cuts and Jobs Act deferral				(13.5		)
Natural gas production gathering fees				(0.4		)
Property taxes recovered in trackers	6.3			4.1
Gas production gathering fees	0.4
Production tax credits flowed-through trackers				1.2
Change in Items Offset Within Net Income	6.7			(8.6		)
Increase in Gross Margin	$	18.9		$	27.6

Consolidated gross margin for items impacting net income increased ~~$12.2~~$36.2 million, due to the following:

~~The inclusion~~A reduction in ~~our 2016 results~~the electric QF liability due to the combination of (i) a periodic adjustment of the ~~MPSC disallowance~~liability for price escalation, which was less than modeled resulting in a liability reduction of ~~both replacement power~~approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million in lower QF related supply costs ~~from a 2013 outage~~due to outages at ~~Colstrip Unit 4 and portfolio modeling costs;~~two facilities;

An increase in electric and natural gas retail volumes due primarily to ~~colder winter and spring~~favorable weather and customer growth;

~~An increase in electric retail volumes due primarily to colder winter weather and customer growth, partly offset by milder spring weather;~~

~~An increase in South Dakota electric revenue due to the timing of the change in customer rates in 2016;~~

~~A decrease in QF related supply costs based on actual QF pricing and output; and~~

Higher demand to transmit energy across our transmission lines due to market conditions and ~~pricing.~~pricing; and

~~These increases were partly offset by:~~

~~The inclusion~~An increase in our ~~2016 results of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings regarding prior period lost revenues; and~~

~~Lower~~Montana gas ~~production margin due primarily to $1.0 million reduction in interim~~ rates ~~of production assets recovered through the natural gas tracker, partly offset by a $0.3 million increase in overhead fees.~~effective September 1, 2017.

The change in consolidated gross margin also includes the following items that had no impact on net income:

A decrease due to the deferral of revenue as a result of the Tax Cuts and Job Act, offset by a decrease in income tax expense;

A decrease in natural gas production gathering fees, offset by reduced operating expenses;

An increase in revenues for property taxes included in trackers, is offset by increased property tax ~~expense with no impact to net income;~~expense; and


	Six Months Ended June 30,								Six Months Ended June 30,
	2017		2016		Change		% Change		2018		2017		Change			% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	156.2	$	152.4	$	3.8	2.5	%	$	148.2	$	150.9	$	(2.7	)	(1.8	)%
Property and other taxes	79.4		70.6		8.8		12.5		85.9		79.4		6.5			8.2
Depreciation and depletion	83.0		79.8		3.2		4.0		87.3		83.0		4.3			5.2
	$	318.6	$	302.8	$	15.8	5.2	%	$	321.4	$	313.3	$	8.1		2.6	%

Consolidated operating, general and administrative expenses were ~~$156.2~~$148.2 million for the six months ended June 30, ~~2017,~~2018, as compared with ~~$152.4~~$150.9 million for the six months ended June 30, ~~2016.~~2017. Primary components of the change include the following:


	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2017 vs. 2016			2018 vs. 2017
	(in millions)			(in millions)
Maintenance costs	$	2.0
Bad debt expense	1.9
Maintenance Costs				$	(3.5	)
Labor	1.4			(2.2		)
Distribution System Infrastructure Project expenses				(1.7		)
Natural gas production gathering expense	0.4			(0.4		)
Employee benefits				2.9
Other				(1.3		)
Operating, General & Administrative Expenses impacting Net Income				(6.2		)

Operating, General & Administrative Expenses Offset in Other Income
Pension and other postretirement benefits				5.3
Non-employee directors deferred compensation	(1.3		)	(1.8		)
Insurance reserves	(1.0		)
Other	0.4
Increase in Operating, General & Administrative Expenses	$	3.8
Change in Items Offset Within Other Income				3.5
Decrease in Operating, General & Administrative Expenses				$	(2.7	)

~~The increase in~~Consolidated operating, general and administrative expenses ~~is primarily~~for items impacting net income decreased $6.2 million due to the following:

~~Higher~~Lower maintenance costs at ~~our Dave Gates Generating Station and Colstrip Unit 4;~~electric generating facilities;

~~Higher bad debt expense due to an increase in revenues as a result of colder weather;~~

~~Increased~~Decreased labor costs due primarily to ~~compensation increases and~~ more time being spent by employees on capital rather than maintenance projects (which are expensed) ~~rather than capital projects;~~;

Lower Distribution System Infrastructure Project related expenses, which concluded in 2017; and

~~An increase in natural~~Lower gas production gathering expense (offset by ~~higher~~lower gathering fees discussed above).

These ~~increases~~decreases were partly offset by an increase in employee benefit costs primarily due to higher medical and pension expense.

The change in consolidated operating, general and administrative expenses also includes the following items that are offset in ~~part by:~~other income (expense) below and had no impact on net income:

The regulatory treatment of the non-service cost components of pension and postretirement benefit expense; and

The change in value of non-employee directors deferred compensation due to changes in our stock ~~price (offset by changes in other income with no impact on net income); and~~

~~A decrease in insurance reserves primarily due to the amount recorded in 2016 related to the Billings, Montana refinery outage.~~price.

Property and other taxes were ~~$79.4~~$85.9 million for the six months ended June 30, ~~2017,~~2018, as compared with ~~$70.6~~$79.4 million in the same period of ~~2016.~~2017. This increase was primarily due to plant additions and higher estimated property valuations in Montana. We expect property tax expense to increase by approximately ~~$10~~$7.0 million on an annual basis in ~~2017~~2018 as compared with ~~2016.~~2017.

Depreciation and depletion expense was ~~$83.0~~$87.3 million for the six months ended June 30, ~~2017,~~2018, as compared with ~~$79.8~~$83.0 million in the same period of ~~2016.~~2017. This increase was primarily due to plant additions.

Consolidated operating income for the six months ended June 30, ~~2017~~2018 was ~~$128.8~~$153.7 million as compared with ~~$125.7~~$134.1 million in the same period of ~~2016.~~2017. This increase was primarily due to the adjustment of our electric QF liability and favorable weather, partly offset by the overall increase in ~~gross margin~~operating expenses, as discussed ~~above, offset in part by higher operating expenses.~~above.

Consolidated interest expense for the six months ended June 30, ~~2017~~2018 was ~~$46.8~~$46.2 million, as compared with ~~$50.9~~$46.8 million in the same period of ~~2016.~~2017. This decrease was primarily due to ~~$2.9 million of interest associated with~~ the ~~2016 MPSC disallowance as discussed above along with the debt~~ refinancing of ~~the Pollution Control Revenue Refunding Bonds during the third quarter of 2016.~~debt in 2017, partly offset by rising interest rates.

Consolidated other ~~income~~expense for the six months ended June 30, ~~2017,~~2018, was ~~$3.6~~$0.3 million, as compared with ~~$4.3~~$1.6 million in the same period of ~~2016.~~2017. This includes a decrease ~~was primarily due to~~in other pension expense, partly offset by a ~~$1.3 million~~ decrease in the value of deferred shares held in trust for non-employee directors deferred compensation ~~(which, as discussed above, is~~(both of which are offset ~~by a corresponding decrease to~~in operating, general and administrative ~~expenses). This decrease was offset in part by higher~~expenses with no impact to net income) and lower capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, ~~2017~~2018 was ~~$7.3~~$5.0 million, as compared with ~~$3.6~~$7.3 million in the same period of ~~2016.~~2017. Our effective tax rate for the six months ended June 30, ~~2017~~2018 was ~~8.5%~~4.7% as compared with ~~4.6%~~8.5% for the same period of 2016. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which reduced tax expense for the six months ended June 30, 2016.2017.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):


	Six Months Ended June 30,										Six Months Ended June 30,
	2017					2016					2018					2017
Income Before Income Taxes	$	85.7				$	79.0				$	107.3				$	85.7

Income tax calculated at 35% federal statutory rate	30.0			35.0	%	27.7			35.0	%
Income tax calculated at federal statutory rate											22.5			21.0	%	30.0			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(1.3		)	(1.5	)	(2.3		)	(2.9	)	1.5			1.5		(1.3		)	(1.5	)
Flow-through repairs deductions	(13.6		)	(15.8	)	(13.7		)	(17.3	)	(10.7		)	(10.0	)	(13.6		)	(15.8	)
Production tax credits	(5.3		)	(6.2	)	(5.1		)	(6.5	)	(6.4		)	(6.0	)	(5.3		)	(6.2	)
Plant and depreciation of flow through items	(2.1		)	(2.5	)	(1.2		)	(1.5	)	(1.5		)	(1.4	)	(2.1		)	(2.5	)
Share-based compensation	(0.4		)	(0.5	)	(1.6		)	(2.1	)	0.3			0.3		(0.4		)	(0.5	)
Prior year permanent return to accrual adjustments	—			—		(0.1		)	(0.1	)
Other, net	—			—		(0.1		)	—		(0.7		)	(0.7	)	—			—
	(22.7		)	(26.5	)	(24.1		)	(30.4	)	(17.5		)	(16.3	)	(22.7		)	(26.5	)

Income Tax Expense	$	7.3		8.5	%	$	3.6		4.6	%	$	5.0		4.7	%	$	7.3		8.5	%

Consolidated net income for the six months ended June 30, ~~2017~~2018 was ~~$78.4~~$102.3 million as compared with ~~$75.4~~$78.4 million for the same period in ~~2016.~~2017. This increase was primarily due to ~~improved gross margin as~~ a ~~result~~gain related to the adjustment of our electric QF liability, favorable weather, and lower ~~interest~~income tax expense, partly offset by ~~higher~~the overall increase in operating ~~and income tax expense.~~expenses, as discussed above.

ELECTRIC SEGMENT

We have various classifications of electric revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers.

Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers.

Transmission: Reflects transmission revenues regulated by the FERC.

Ancillary Services: FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.

Wholesale and ~~other: Our South Dakota service territory is a market participant~~other are largely gross margin neutral as they are offset by changes in ~~the Southwest Power Pool, where we buy and sell wholesale energy and reserves through the operation~~cost of ~~a single, consolidated balancing authority. This line also includes miscellaneous electric revenues.~~sales.

Three Months Ended June 30, ~~2017~~2018 Compared with the Three Months Ended June 30, ~~2016~~2017


	Results									Results
	2017		2016		Change			% Change		2018			2017		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	196.0	$	200.6	$	(4.6	)	(2.3	)%	$	193.6		$	196.0	$	(2.4	)	(1.2	)%
Regulatory amortization	4.5		16.1		(11.6		)	(72.0	)	(1.3		)	4.5		(5.8		)	(128.9	)
Total retail revenues	200.5		216.7		(16.2		)	(7.5	)	192.3			200.5		(8.2		)	(4.1	)
Transmission	13.1		12.7		0.4			3.1		16.2			13.1		3.1			23.7
Ancillary services	0.4		0.4		—			—
Wholesale and other	19.9		18.6		1.3			7.0
Wholesale and Other										1.2			20.3		(19.1		)	(94.1	)
Total Revenues	233.9		248.4		(14.5		)	(5.8	)	209.7			233.9		(24.2		)	(10.3	)
Total Cost of Sales	70.1		72.2		(2.1		)	(2.9	)	19.6			70.1		(50.5		)	(72.0	)
Gross Margin	$	163.8	$	176.2	$	(12.4	)	(7.0	)%
Gross Margin⁽¹⁾										$	190.1		$	163.8	$	26.3		16.1	%

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2017		2016		2017	2016	2017	2016	2018		2017		2018	2017	2018	2017
	(in thousands)								(in thousands)
Montana	$	59,740	$	63,044	503	522	294,721	290,743	$	59,480	$	59,740	516	503	298,897	294,721
South Dakota	12,832		12,640		110	113	50,158	49,946	14,385		12,832		130	110	50,493	50,158
Residential	72,572		75,684		613	635	344,879	340,689	73,865		72,572		646	613	349,390	344,879
Montana	83,028		85,611		764	775	66,277	65,421	79,648		83,028		762	764	67,339	66,277
South Dakota	21,400		20,706		230	231	12,687	12,642	22,271		21,400		250	230	12,804	12,687
Commercial	104,428		106,317		994	1,006	78,964	78,063	101,919		104,428		1,012	994	80,143	78,964
Industrial	10,087		9,772		554	538	75	73	10,714		10,087		600	554	75	75
Other	8,920		8,841		51	50	6,205	6,222	7,140		8,920		36	51	6,026	6,205
Total Retail Electric	$	196,007	$	200,614	2,212	2,229	430,123	425,047	$	193,638	$	196,007	2,294	2,212	435,634	430,123


	Cooling Degree Days			2017 as compared with:		Cooling Degree Days			2018 as compared with:
	2017	2016	Historic Average	2016	Historic Average	2018	2017	Historic Average	2017	Historic Average
Montana	57	89	47	36% colder	21% warmer	32	57	55	44% colder	42% colder
South Dakota	91	98	58	7% colder	57% warmer	167	91	51	84% warmer	227% warmer


	Heating Degree Days			2017 as compared with:		Heating Degree Days			2018 as compared with:
	2017	2016	Historic Average	2016	Historic Average	2018	2017	Historic Average	2017	Historic Average
Montana	1,061	973	1,223	9% colder	13% warmer	1,089	1,061	1,195	3% colder	9% warmer
South Dakota	1,321	1,246	1,410	6% colder	6% warmer	1,712	1,321	1,535	30% colder	12% colder

The following summarizes the components of the changes in electric gross margin for the three months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Gross Margin 2017 vs. 2016			Gross Margin 2018 vs. 2017
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
Lost revenue adjustment mechanism	$	(13.4	)
QF liability adjustment				$	25.1
Retail volumes	(1.4		)	2.5
MPSC 2016 disallowance (adjustment)	(0.8		)
Transmission	0.4			1.4
QF adjustment	0.4
Other	(0.5		)	0.9
Change in Gross Margin Impacting Net Income	(15.3		)	29.9

Gross Margin Items Offset in Operating Expenses
Tax Cuts and Jobs Act deferral				(7.0		)
Property taxes recovered in trackers	2.9			2.7
Production tax credits flowed-through trackers				0.7
Change in Items Offset Within Net Income	2.9			(3.6		)
Decrease in Gross Margin	$	(12.4	)
Increase in Gross Margin⁽¹⁾				$	26.3

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Gross margin for items impacting net income ~~decreased $15.3~~increased $29.9 million including the following:

~~The recognition~~A reduction in ~~2016~~the QF liability due to the combination of ~~$13.4~~(i) a periodic adjustment of the liability for price escalation, which was less than modeled resulting in a liability reduction of approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million ~~of deferred revenue as a result of a MPSC final order~~ in ~~our tracker filings;~~lower QF related supply costs due to outages at two facilities;

~~A decrease~~An increase in ~~electric residential and commercial~~ retail volumes due primarily to ~~milder spring~~favorable weather ~~partly offset by growth in our residential~~ and ~~industrial customers;~~customer growth; and

~~An adjustment in 2016 in the disallowance of modeling costs based on the MPSC final order.~~

~~These decreases were partly offset by:~~

Higher demand to transmit energy across our transmission lines due to market conditions and ~~pricing; and~~pricing.

The change in gross margin also includes the following items that had no impact on net income:

A decrease due to the deferral of revenue as a result of the Tax Cuts and Job Act, offset by a decrease in ~~QF related supply costs based on actual QF pricing and output.~~income tax expense;

~~The~~An increase in revenues for property taxes included in trackers, is offset by increased property tax ~~expense with no impact~~expense; and

An increase in revenue due to ~~net income.~~the decrease in production tax credit benefits passed through to customers in our tracker mechanisms, which are offset by increased income tax expense.

The change in regulatory amortization revenue ~~includes the recognition of deferred revenue in 2016, as discussed above and~~is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our ~~customers. These timing differences have~~customers, which has a minimal impact on gross margin. In addition, while heating and cooling degree days may fluctuate significantly during the second quarter, our electric customer usage is not highly sensitive to these changes between the heating and cooling seasons. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, ~~2017~~2018 Compared with the Six Months Ended June 30, ~~2016~~2017


	Results										Results
	2017			2016		Change			% Change		2018			2017			Change			% Change
	(dollars in millions)										(dollars in millions)
Retail revenues	$	430.7		$	410.8	$	19.9		4.8	%	$	423.0		$	430.7		$	(7.7	)	(1.8	)%
Regulatory amortization	(0.7		)	12.7		(13.4		)	(105.5	)	(9.4		)	(0.7		)	(8.7		)	(1,242.9	)
Total retail revenues	430.0			423.5		6.5			1.5		413.6			430.0			(16.4		)	(3.8	)
Transmission	25.5			25.3		0.2			0.8		31.5			25.5			6.0			23.5
Ancillary services	0.8			0.8		—			—
Wholesale and other	43.8			40.1		3.7			9.2
Wholesale and Other											3.0			44.6			(41.6		)	(93.3	)
Total Revenues	500.1			489.7		10.4			2.1		448.1			500.1			(52.0		)	(10.4	)
Total Cost of Sales	155.5			155.8		(0.3		)	(0.2	)	76.9			155.5			(78.6		)	(50.5	)
Gross Margin	$	344.6		$	333.9	$	10.7		3.2	%
Gross Margin⁽¹⁾											$	371.2		$	344.6		$	26.6		7.7	%

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2018		2017		2018	2017	2018	2017
	(in thousands)
Montana	$	146,731	$	150,548	1,277	1,264	298,631	294,471
South Dakota	33,068		30,168		317	289	50,500	50,167
Residential	179,799		180,716		1,594	1,553	349,131	344,638
Montana	163,287		171,136		1,566	1,579	67,261	66,194
South Dakota	46,282		43,810		520	485	12,727	12,616
Commercial	209,569		214,946		2,086	2,064	79,988	78,810
Industrial	21,476		20,952		1,207	1,132	75	75
Other	12,137		14,057		58	74	5,381	5,443
Total Retail Electric	$	422,981	$	430,671	4,945	4,823	434,575	428,966

Revenues Megawatt Hours (MWH) Avg. Customer Counts
2017 2016 2017 2016 2017 2016
(in thousands)
Montana $ 150,548
$ 139,734
1,264
1,189
294,471
290,399
South Dakota 30,168
27,878
289
281
50,167
49,928
Residential 180,716
167,612
1,553
1,470
344,638
340,327
Montana 171,136
168,634
1,579
1,568
66,194
65,349
South Dakota 43,810
41,200
485
482
12,616
12,554
Commercial 214,946
209,834
2,064
2,050
78,810
77,903
Industrial 20,952
19,690
1,132
1,073
75
73
Other 14,057
13,616
74
73
5,443
5,445
Total Retail Electric $ 430,671
$ 410,752
4,823
4,666
428,966
423,748



	Cooling Degree Days			2018 as compared with:
	2018	2017	Historic Average	2017	Historic Average
Montana	32	57	55	44% colder	42% colder
South Dakota	167	91	51	84% warmer	227% warmer

Cooling Degree Days 2017 as compared with:
2017 2016 Historic Average 2016 Historic Average
Montana 57 89 47 36% colder 21% warmer
South Dakota 91 98 58 7% colder 57% warmer


	Heating Degree Days			2017 as compared with:		Heating Degree Days			2018 as compared with:
	2017	2016	Historic Average	2016	Historic Average	2018	2017	Historic Average	2017	Historic Average
Montana	4,437	3,852	4,496	15% colder	1% warmer	4,697	4,437	4,373	6% colder	7% colder
South Dakota	5,211	4,920	5,535	6% colder	6% warmer	6,076	5,211	5,574	17% colder	9% colder

The following summarizes the components of the changes in electric gross margin for the six months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Gross Margin 2017 vs. 2016			Gross Margin 2018 vs. 2017
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
MPSC 2016 disallowance	$	9.5
QF liability adjustment				$	25.1
Retail volumes	7.2			3.6
South Dakota rate increase	1.2
QF adjustment	0.4
Transmission	0.2			2.9
2016 Lost revenue adjustment mechanism	(13.4		)
Other	0.8			1.0
Change in Gross Margin Impacting Net Income	5.9			32.6

Gross Margin Items Offset in Operating Expenses
Tax Cuts and Jobs Act deferral				(11.5		)
Property taxes recovered in trackers	4.8			4.3
Production tax credits flowed-through trackers				1.2
Change in Items Offset Within Net Income	4.8			(6.0		)
Increase in Gross Margin	$	10.7		$	26.6

Gross margin for items impacting net income increased ~~$5.9~~$32.6 million including the following:

~~The inclusion~~A reduction in ~~2016~~the QF liability due to the combination of (i) a periodic adjustment of the ~~MPSC disallowance~~liability for price escalation, which was less than modeled resulting in a liability reduction of ~~both replacement power~~approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million in lower QF related supply costs ~~from a 2013 outage~~due to outages at ~~Colstrip Unit 4 and portfolio modeling costs;~~two facilities;

An increase in ~~residential and commercial~~ retail volumes due primarily to ~~colder winter~~favorable weather and ~~growth in our residential and industrial customers, partly offset by milder spring weather;~~

~~An increase in South Dakota electric rates due to the timing of the change in~~ customer ~~rates in 2016;~~

~~A decrease in QF related supply costs based on actual QF pricing and output;~~growth; and

Higher demand to transmit energy across our transmission lines due to market conditions and pricing.

~~These increases were partly offset by~~The change in gross margin also includes the ~~recognition in 2016~~following items that had no impact on net income:

A decrease due to the deferral of ~~$13.4 million of deferred~~ revenue as a result of the Tax Cuts and Job Act, offset by a ~~MPSC final order~~decrease in ~~our tracker filings. In addition, the~~income tax expense;

An increase in revenues for property taxes included in trackers, is offset by increased property tax ~~expense with no impact~~expense; and

An increase in revenue due to ~~net income.~~the decrease in production tax credit benefits passed through to customers in our tracker mechanisms, which are offset by increased income tax expense.

The change in regulatory amortization revenue is ~~primarily~~ due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

NATURAL GAS SEGMENT

We have various classifications of natural gas revenues, defined as follows:

Retail: Sales of natural gas to residential, commercial and industrial customers.

Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in cost of sales and therefore has minimal impact on gross margin.

Wholesale: Primarily represents transportation and storage for others.

Three Months Ended June 30, ~~2017~~2018 Compared with the Three Months Ended June 30, ~~2016~~2017


	Results									Results
	2017		2016		Change			% Change		2018			2017		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	38.2	$	33.1	$	5.1		15.4	%	$	43.4		$	38.2	$	5.2		13.6	%
Regulatory amortization	2.0		2.4		(0.4		)	(16.7	)	(1.9		)	2.0		(3.9		)	(195.0	)
Total retail revenues	40.2		35.5		4.7			13.2		41.5			40.2		1.3			3.2
Wholesale and other	9.8		9.2		0.6			6.5		10.6			9.8		0.8			8.2
Total Revenues	50.0		44.7		5.3			11.9		52.1			50.0		2.1			4.2
Total Cost of Sales	13.9		9.5		4.4			46.3		12.6			13.9		(1.3		)	(9.4	)
Gross Margin(1)	$	36.1	$	35.2	$	0.9		2.6	%	$	39.5		$	36.1	$	3.4		9.4	%

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2017		2016		2017	2016	2017	2016	2018		2017		2018	2017	2018	2017
	(in thousands)								(in thousands)
Montana	$	16,507	$	14,228	1,981	1,765	170,311	168,006	$	17,574	$	16,507	2,093	1,981	172,638	170,311
South Dakota	4,297		3,980		512	487	39,436	39,088	5,607		4,297		701	512	39,582	39,436
Nebraska	4,104		3,425		436	420	37,192	37,034	4,991		4,104		591	436	37,269	37,192
Residential	24,908		21,633		2,929	2,672	246,939	244,128	28,172		24,908		3,385	2,929	249,489	246,939
Montana	8,211		7,097		1,034	922	23,548	23,238	8,779		8,211		1,109	1,034	23,896	23,548
South Dakota	2,750		2,343		521	516	6,536	6,421	3,645		2,750		692	521	6,668	6,536
Nebraska	2,057		1,673		342	336	4,765	4,707	2,413		2,057		426	342	4,813	4,765
Commercial	13,018		11,113		1,897	1,774	34,849	34,366	14,837		13,018		2,227	1,897	35,377	34,849
Industrial	156		153		21	22	252	259	181		156		24	21	244	252
Other	165		190		24	30	158	158	208		165		31	24	163	158
Total Retail Gas	$	38,247	$	33,089	4,871	4,498	282,198	278,911	$	43,398	$	38,247	5,667	4,871	285,273	282,198


	Heating Degree Days			2017 as compared with:		Heating Degree Days			2018 as compared with:
	2017	2016	Historic Average	2016	Historic Average	2018	2017	Historic Average	2017	Historic Average
Montana	1,133	1,011	1,265	12% colder	10% warmer	1,128	1,133	1,243	Remained flat	9% warmer
South Dakota	1,321	1,246	1,410	6% colder	6% warmer	1,712	1,321	1,535	30% colder	12% colder
Nebraska	1,028	1,038	1,154	1% warmer	11% warmer	1,328	1,028	1,257	29% colder	6% colder

The following summarizes the components of the changes in natural gas gross margin for the three months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Gross Margin 2017 vs. 2016			Gross Margin 2018 vs. 2017
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	1.3		$	1.5
2016 Lost revenue adjustment mechanism	(0.8		)
Production	(0.1		)
Montana rates				0.3
Other	(0.2		)	0.4
Change in Gross Margin Impacting Net Income	0.2			2.2

Gross Margin Items Offset in Operating Expenses
Tax Cuts and Jobs Act deferral				0.8
Property taxes recovered in trackers				0.8
Production gathering fees	0.4			(0.4		)
Property taxes recovered in trackers	0.3
Change in Items Offset Within Net Income	0.7			1.2
Increase in Gross Margin(1)	$	0.9		$	3.4

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Gross margin for items impacting net income increased ~~$0.2~~$2.2 million ~~due to an~~including the following:

An increase in retail volumes due primarily to favorable weather and customer growth; and

An increase in our Montana ~~and South Dakota jurisdictions due to colder spring weather and customer growth, partly offset by the following:~~

~~The recognition in 2016 of $0.8 million of deferred revenue as a result of a MPSC final order in our tracker filings; and~~

~~A decrease in production margin due primarily to a $0.4 million reduction in interim~~gas rates ~~partly offset by a $0.3 million increase in overhead fees.~~effective September 1, 2017.

The change in ~~consolidated~~ gross margin also includes the following items that had no impact on net income:

An increase ~~in production gathering fees~~due to the deferral of revenue as a result of the Tax Cuts and Job Act is offset by an increase in ~~operating expenses; and~~income tax expense;

An increase in revenues for property taxes included in trackers, is offset by increased property tax ~~expense with no impact to net income.~~expense; and

A decrease in natural gas production gathering fees (offset by reduced operating expenses).

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, ~~2017~~2018 Compared with the Six Months Ended June 30, ~~2016~~2017


	Results											Results
	2017			2016			Change			% Change		2018			2017			Change			% Change
	(dollars in millions)											(dollars in millions)
Retail revenues	$	137.1		$	117.0		$	20.1		17.2	%	$	142.6		$	137.1		$	5.5		4.0	%
Regulatory amortization	(6.6		)	(0.6		)	(6.0		)	1,000.0		(8.2		)	(6.6		)	(1.6		)	(24.2	)
Total retail revenues	130.5			116.4			14.1			12.1		134.4			130.5			3.9			3.0
Wholesale and other	20.6			19.5			1.1			5.6		20.8			20.6			0.2			1.0
Total Revenues	151.1			135.9			15.2			11.2		155.2			151.1			4.1			2.7
Total Cost of Sales	48.3			41.3			7.0			16.9		51.4			48.3			3.1			6.4
Gross Margin(1)	$	102.8		$	94.6		$	8.2		8.7	%	$	103.8		$	102.8		$	1.0		1.0	%

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2017		2016		2017	2016	2017	2016	2018		2017		2018	2017	2018	2017
	(in thousands)								(in thousands)
Montana	$	60,275	$	50,553	7,903	6,722	170,238	167,895	$	58,477	$	60,275	7,998	7,903	172,495	170,238
South Dakota	15,101		14,128		2,027	1,874	39,563	39,219	17,025		15,101		2,376	2,027	39,740	39,563
Nebraska	13,134		11,244		1,684	1,558	37,332	37,172	16,404		13,134		2,007	1,684	37,424	37,332
Residential	88,510		75,925		11,614	10,154	247,133	244,286	91,906		88,510		12,381	11,614	249,659	247,133
Montana	30,144		24,982		4,125	3,446	23,550	23,231	29,311		30,144		4,193	4,125	23,881	23,550
South Dakota	10,179		8,952		1,856	1,771	6,558	6,442	11,456		10,179		2,167	1,856	6,694	6,558
Nebraska	6,969		5,946		1,216	1,136	4,793	4,727	8,529		6,969		1,408	1,216	4,839	4,793
Commercial	47,292		39,880		7,197	6,353	34,901	34,400	49,296		47,292		7,768	7,197	35,414	34,901
Industrial	662		590		93	85	254	261	720		662		107	93	246	254
Other	612		576		95	92	158	158	651		612		105	95	163	158
Total Retail Gas	$	137,076	$	116,971	18,999	16,684	282,446	279,105	$	142,573	$	137,076	20,361	18,999	285,482	282,446


	Heating Degree Days			2017 as compared with:		Heating Degree Days			2018 as compared with:
	2017	2016	Historic Average	2016	Historic Average	2018	2017	Historic Average	2017	Historic Average
Montana	4,601	3,998	4,509	15% colder	2% colder	4,677	4,601	4,480	2% colder	4% colder
South Dakota	5,211	4,920	5,535	6% colder	6% warmer	6,076	5,211	5,574	17% colder	9% colder
Nebraska	4,110	3,989	4,578	3% colder	10% warmer	4,928	4,110	4,611	20% colder	7% colder

The following summarizes the components of the changes in natural gas gross margin for the six months ended June 30, ~~2017~~2018 and ~~2016~~:2017:


	Gross Margin 2017 vs. 2016			Gross Margin 2018 vs. 2017
	(in millions)			(in millions)
Gross Margin Items Impacting Net Income
Montana rates				$	2.2
Retail volumes	$	7.3		1.9
2016 Lost revenue adjustment mechanism	(0.8		)
Production	(0.7		)
Other	0.5			(0.5		)
Change in Gross Margin Impacting Net Income	6.3			3.6

Gross Margin Items Offset in Operating Expenses
Tax Cuts and Jobs Act deferral				(2.0		)
Production gathering fees				(0.4		)
Property taxes recovered in trackers	1.5			(0.2		)
Production gathering fees	0.4
Change in Items Offset Within Net Income	1.9			(2.6		)
Increase in Gross Margin(1)	$	8.2		$	1.0

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Gross margin for items impacting net income increased ~~$6.3~~$3.6 million ~~from an~~including the following:

An increase in our Montana gas rates effective September 1, 2017; and

An increase in retail volumes due primarily to ~~colder winter and spring~~favorable weather and customer ~~growth, partly offset by the following items:~~

~~The recognition in 2016 of $0.8 million of deferred revenue as a result of a MPSC final order in our tracker filings; and~~

~~A decrease in production margin due primarily to a $1.0 million reduction in interim rates, partly offset by a $0.3 million increase in overhead fees.~~growth.

The change in ~~consolidated~~ gross margin also includes the following items that had no impact on net income:

~~An increase~~A decrease due to the deferral of revenue as a result of the Tax Cuts and Job Act is offset by a decrease in income tax expense;

A decrease in natural gas production gathering fees, offset by reduced operating expenses; and

A decrease in revenues for property taxes included in trackers, is offset by ~~increased~~decreased property tax ~~expense with no impact to net income; and~~

~~An increase in production gathering fees is offset by an increase in operating expenses.~~expense.

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.



LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Funds

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. We believe our cash flows from operations and existing borrowing capacity should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. In addition, a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements, and we may defer a portion of our planned capital expenditures as necessary.

We issue debt securities to refinance retiring maturities, ~~reduce short-term debt,~~ fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities, we utilize available cash flow, debt capacity and equity issuances that allow us to maintain investment grade ratings.

In September 2017, we entered into an Equity Distribution Agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we offered and sold shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended June 30, 2018, we issued 835,765 shares of our common stock at an average price of $54.45, for net proceeds of $44.9 million, which is net of sales commissions and other fees paid of approximately $0.6 million. These issuances concluded this program. Since inception of the program, we sold 1,724,703 shares of our common stock at an average price of $57.98 per share. Net proceeds received were approximately $98.6 million, which are net of sales commissions and other fees paid of approximately $1.4 million.

We plan to maintain a 50 - 55 percent debt to total capital ratio excluding capital leases, and expect to continue to target a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

~~Short-term liquidity~~Liquidity is provided by internal cash flows and the ~~sale of commercial paper and~~ use of our revolving credit facilities. We have a $400 million revolving credit facility. In addition, on March 27, 2018, we entered into a $25 million revolving credit facility, maturing March 27, 2020, to provide swingline borrowing capability. We utilize availability under our ~~short-term borrowings and / or revolver availability~~revolvers to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. ~~Short-term~~We also may use borrowings ~~may also be used~~under our revolvers to temporarily fund utility capital requirements. As of June 30, ~~2017~~,2018, our total net liquidity was approximately ~~$113.2~~$214.6 million, including ~~$16.9~~$5.6 million of cash and ~~$96.3~~$209.0 million of revolving credit facility availability. ~~Revolving~~Availability under our revolving credit ~~facility availability~~facilities was ~~$119.3~~$213.0 million as of July ~~21, 2017.~~

~~The following table presents additional information about short term borrowings during the six months ended June 30, 2017 (in millions):~~

Amount outstanding at period end $ 303.7
Daily average amount outstanding $ 223.2
Maximum amount outstanding $ 303.7
13, 2018.

Factors Impacting our Liquidity

Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is currently recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult. In 2017, a Montana ~~law defining~~statute that provided for mandatory recovery of our ~~current~~prudently incurred electric ~~tracking mechanism~~supply costs was ~~repealed effective July 1, 2017,~~amended, and that statute now gives the MPSC ~~has outlined~~discretion as to whether to approve electric supply costs. The MPSC opened a new docket and initiated a process ~~for implementing a replacement mechanism. We expect~~to develop a new ~~mechanism to be established, but cannot predict how this may impact the timing of recovery of cash flows associated with our Montana~~ electric supply ~~costs.~~recovery mechanism.

As of June 30, ~~2017~~2018, we are over collected on our supply trackers by approximately $3.2 million. We were under collected on our supply trackers by ~~approximately $6.5 million, as compared with an under collection of $11.7~~$13.2 million as of December 31, ~~2016,~~2017 and ~~$9.6~~$6.5 million as of June 30, ~~2016~~2017.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, ~~and~~may impact our trade credit ~~availability.~~availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July ~~21, 2017,~~13, 2018, our current ratings with these agencies are as follows:



	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch (1)	A	A-	F2	~~Stable~~Negative
Moody’s ~~(1)~~(2)	A2A3	~~Baa1~~Baa2	Prime-2	~~Negative~~Stable
S&P	A-	BBB	A-2	Stable

~~_____________________~~_________________________

(1) In ~~March 2017,~~February 2018, Fitch affirmed our ratings, but revised our outlook from stable to negative citing continued regulatory headwinds in Montana and expected weakness in leverage metrics through 2021. Fitch also indicated an adverse outcome in either our Montana electric supply tracker docket or upcoming electric general rate case would likely result in a one-notch downgrade.

(2) In May 2018, Moody's downgraded our senior secured rating to ~~A2,~~A3 from ~~A1,~~A2, and our unsecured credit rating to Baa2 from Baa1 and revised our outlook from ~~A3, while maintaining a~~ negative ~~outlook.~~to stable. Moody's cited an extended period of weak financial metrics and ~~a heightened degree of~~challenging regulatory ~~uncertainty~~relationship in Montana as reasons for the downgrade. ~~Moody's maintained a negative outlook, citing a more contentious regulatory relationship in Montana, our primary regulatory jurisdiction, resulting in unpredictable regulatory outcomes.~~

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):


	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
Operating Activities
Net income	$	78.4		$	75.4		$	102.3		$	78.4
Non-cash adjustments to net income	92.8			88.3			96.9			92.8
Changes in working capital	9.6			(26.8		)	57.1			10.8
Other noncurrent assets and liabilities	(3.0		)	4.1			(9.1		)	(3.0		)
Cash Provided by Operating Activities	177.8			141.0			247.2			179.0

Investing Activities
Property, plant and equipment additions	(119.1		)	(121.2		)	(116.5		)	(119.1		)
Other	0.4			0.1
Acquisitions							(18.5		)	—
Proceeds from sale of assets							—			0.4
Cash Used in Investing Activities	(118.7		)	(121.1		)	(135.0		)	(118.7		)

Financing Activities
Issuances of long-term debt, net	—			5.0
Issuances of short-term borrowings, net	2.8			26.9
Proceeds from issuance of common stock, net							44.9			—
Line of credit borrowings, net							216.0			—
(Repayments) issuances of short-term borrowings, net							(319.6		)	2.8
Dividends on common stock	(50.4		)	(47.9		)	(54.3		)	(50.4		)
Financing costs	(0.1		)	(5.3		)	(0.1		)	(0.1		)
Other	0.4			(1.6		)	1.8			0.4
Cash Used in Financing Activities	(47.3		)	(22.9		)	(111.3		)	(47.3		)

Increase (Decrease) in Cash and Cash Equivalents	$	11.8		$	(3.0	)
Cash and Cash Equivalents, beginning of period	$	5.1		$	12.0
Cash and Cash Equivalents, end of period	$	16.9		$	9.0
Increase in Cash, Cash Equivalents, and Restricted Cash							$	0.9		$	13.0
Cash, Cash Equivalents, and Restricted Cash, beginning of period							$	12.0		$	9.5
Cash, Cash Equivalents, and Restricted Cash, end of period							$	12.9		$	22.5

Cash Provided by Operating Activities

As of June 30, ~~2017~~,2018, cash, ~~and~~ cash equivalents, and restricted cash were ~~$16.9~~$12.9 million as compared with ~~$5.1~~$12.0 million at December 31, ~~2016~~2017 and ~~$9.0~~$22.5 million at June 30, ~~2016~~.2017. Cash provided by operating activities totaled $~~177.8~~247.2 million for the six months ended June 30, ~~2017~~2018 as compared with $~~141.0~~179.0 million during the six months ended June 30, ~~2016.~~2017. This increase in operating cash flows is primarily due to higher net income, improved customer receipts and recovery of certain costs through our electric and natural gas trackers, the receipt of insurance proceeds, and lower ~~2016 cash flows due to customer refunds associated with~~priced gas storage injections during the ~~DGGS FERC ruling and interim rates in our South Dakota electric rate case of approximately $30.8 million and $7.2 million, respectively.~~current period.

Cash Used in Investing Activities

Cash used in investing activities ~~decreased~~increased by approximately ~~$2.4~~$16.3 million as compared with the first six months of ~~2016. Plant~~2017. During June 2018, we purchased the 9.7 MW Two Dot wind project in Montana for approximately $18.5 million. Other plant additions during ~~2017~~the first six months of 2018 include maintenance additions of approximately $~~58.9~~91.6 million, and capacity related capital expenditures of approximately $24.9 million. Plant additions during the first six months of 2017 included maintenance additions of approximately $58.9 million, capacity related capital expenditures of approximately $43.7 million, and infrastructure capital expenditures of approximately ~~$16.5 million~~. Plant additions during the first six months of 2016 included maintenance additions of approximately $63.4 million, capacity related capital expenditures of approximately $34.4 million, and infrastructure capital expenditures of approximately $23.4$16.5 million.

Cash Used in Financing Activities

Cash used in financing activities totaled $~~47.3~~111.3 million during the six months ended June 30, ~~2017~~2018 as compared with ~~$22.9~~$47.3 million during the six months ended June 30, ~~2016.~~2017. During the six months ended June 30, 2018, net cash used in

financing activities reflects net repayments of commercial paper of $319.6 million and the payment of dividends of $54.3 million. These impacts were partially offset by issuances under our revolving lines of credit of $216.0 million and proceeds from the issuance of common stock of $44.9 million. During the six months ended June 30, 2017, net cash used in financing activities ~~reflects~~included the payment of dividends of $50.4 million, partially offset by net issuances of commercial paper of $2.8 million. During the six months ended June 30, 2016, net cash used in financing activities included payments of dividends of $47.9 million and the payment of financing costs of $5.3 million, partially offset by net issuances of commercial paper of $26.9 million and net proceeds from the issuance of debt of $5.0 million.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of June 30, ~~2017~~2018. See our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017 for additional discussion.


	Total		2017		2018		2019		2020		2021		Thereafter		Total		2018		2019		2020		2021		2022		Thereafter
	(in thousands)														(in thousands)
Long-term debt	$	1,793,797	$	—	$	—	$	250,000	$	—	$	—	$	1,543,797	$	2,009,827	$	—	$	—	$	—	$	216,000	$	—	$	1,793,827
Capital leases	25,373		1,027		2,133		2,298		2,476		2,668		14,771		23,319		1,106		2,298		2,476		2,668		2,875		11,896
Short-term borrowings	303,658		303,658		—		—		—		—		—
Estimated pension and other postretirement obligations (1)	65,585		11,956		13,684		13,577		13,274		13,094		N/A		59,869		11,380		12,322		12,196		12,053		11,918		N/A
Qualifying facilities liability (2)	844,725		37,304		76,703		78,836		80,984		82,941		487,957		746,760		36,965		75,278		77,319		79,166		81,060		396,972
Supply and capacity contracts (3)	1,928,020		107,793		159,430		158,478		126,468		110,532		1,265,319		2,204,487		105,692		184,600		150,763		129,806		131,912		1,501,714
Contractual interest payments on debt (4)	1,330,494		40,771		81,541		73,616		65,691		65,393		1,003,482		1,532,175		33,849		77,765		77,765		77,365		71,632		1,193,799
Environmental remediation obligations (1)	5,900		700		1,650		2,150		800		600		N/A		4,338		987		1,072		1,070		604		605		N/A
Total Commitments (5)	$	6,297,552	$	503,209	$	335,141	$	578,955	$	289,693	$	275,228	$	4,315,326	$	6,580,775	$	189,979	$	353,335	$	321,589	$	517,662	$	300,002	$	4,898,208

_________________________


(1)	We estimate cash obligations related to our pension and other postretirement benefit programs and environmental remediation obligations for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.


(2)	Certain QFs require us to purchase minimum amounts of energy at prices ranging from ~~$74~~$74 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately ~~$844.7 million~~.$746.8 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately ~~$654.5~~$596.4 million.


(3)	We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 27 years.


(4)	~~For~~Contractual interest payments includes our revolving credit facilities, which have a variable ~~rate short-term borrowings outstanding, we~~interest rate. We have assumed an average interest rate of ~~1.30%~~2.75% on the outstanding balance through ~~maturity.~~maturity of the facilities.


(5)	Potential tax payments related to uncertain tax positions are not practicable to estimate and have been excluded from this table.



CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

As We continually evaluate the appropriateness of ~~June 30, 2017, there have been no significant changes with regard~~our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the ~~critical~~Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017. ~~The~~There have been no material changes in these policies ~~disclosed included the accounting~~except for the following: ~~goodwill and long-lived assets,~~

Qualifying Facilities Liability

Our electric QF liability ~~revenue recognition,~~consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Under the terms of these contracts, we are required to purchase minimum amounts of energy at prices ranging from $74 to $136 per MWH through 2029. Our estimated gross contractual obligation is approximately $746.8 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $596.4 million through 2029. We maintain an electric QF liability based on the net present value (discounted at 7.75%) of the difference between our estimated obligations under the QFs and the fixed amounts recoverable in rates.

The liability was established based on certain assumptions and projections over the contract terms related to pricing, estimated output and recoverable amounts. Since the liability is based on projections over the next several years, actual output, changes in pricing, contract amendments and regulatory ~~assets~~decisions relating to these facilities could significantly impact the liability and ~~liabilities, pension~~our results of operations in any given year. In assessing the liability each reporting period, we compare our assumptions to actual results and ~~postretirement benefit plans,~~make adjustments as necessary for that period.

One of the contracts contains variable pricing terms, which exposes us to price escalation risks. The estimated annual escalation rate for this contract is a key assumption and ~~income taxes. We continually evaluate~~is based on a combination of historical actual results and market data available for future projections. In recording the ~~appropriateness~~electric QF liability, we estimated an annual escalation rate of 3% over the remaining term of the contract (through June 2024). The actual escalation rate changes annually, which could significantly impact the liability and our ~~estimates and assumptions. Actual~~ results ~~could differ from those estimates.~~of operations.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit ~~facility.~~facilities. The $400 million revolving credit facility bears interest at the lower of prime plus a credit spread, ranging from 0.00% to 0.75%, or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%. ~~To more cost effectively meet short-term cash requirements, we issue commercial paper supported by our~~The $25 million revolving credit ~~facility. Since commercial paper terms are short-term, we are subject~~facility bears interest at the lower of prime plus a credit spread of 0.13%, or available rates tied to ~~interest~~the Eurodollar rate ~~risk.~~plus a credit spread of 0.65%. As of June 30, ~~2017~~2018, we had approximately ~~$303.7~~$216 million ~~of commercial paper outstanding and no~~ in borrowings onunder our revolving credit ~~facility.~~facilities. A 1% increase in interest rates would increase our annual interest expense by approximately ~~$3.0~~$2.2 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability and cost, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is ~~substantially~~ mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

We are exposed to counterparty credit risk related to the ability of these counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. If counterparties seek financial protection under bankruptcy laws, we are exposed to greater financial risks. We are also exposed to counterparty credit risk related to providing transmission service to our customers under our Open Access Transmission Tariff and under gas transportation agreements. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and ~~communicated~~reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

See Note 12, Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.

ITEM 1A. RISK FACTORS -

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.

We are subject to potential unfavorable state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs, which could adversely impact our results of operations and liquidity.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates established by several regulatory commissions. These rates are generally set based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. For instance, our Montana electric utility is regulated by the MPSC and FERC. Differing schedules and regulatory practices between the MPSC and FERC expose us to the risk that we may not recover our costs due to timing of filings and issues such as cost allocation methodology.

While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs.

In addition to rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. Historically, our wholesale costs for electricity and natural gas supply ~~are~~were recovered through various pass-through cost tracking mechanisms in each of the states we serve. In April 2017, the Montana legislature passed HB 193, repealing the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May and July 2017, the MPSC issued NCAs regarding the process to develop a replacement electric tracker mechanism. On July 14, 2017, we filed a proposed electric PCCAM with the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's NCAs and the MDU adjustment mechanism that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline.

The MPSC has also raised questions regarding our earnings as compared to our authorized rate of return for 2016 for electric supply in the HB 193 related docket. In our 2016 annual report to the MPSC we indicated we earned less than our authorized rate of return with electric delivery service and supply combined. In April 2017, we submitted a filing to the MPSC indicating we will file a general electric rate case in 2018 based on a 2017 test year. The NCA established a timeline for the parties to provide comments in July 2017, on the issue of whether the MPSC should require a September 2017 filing. We cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, or the passage of HB 193 reduces our recovery or the timeliness of cash flows, the revised mechanism could adversely impact our results of operations and cash flows.Montana

~~In addition to the proposed changes to our electric tracking mechanism, we~~We have received several unfavorable regulatory rulings in Montana, including:

•In ~~2016,~~2018, the MPSC ~~disallowed approximately $8.2 million~~issued an order in our 2017 property tax tracker filing reducing our recovery of ~~replacement power costs from~~Montana property taxes between general rate filings by applying an alternate allocation methodology. This results in a ~~2013 outage at Colstrip Unit 4,~~lower property tax allocation to our Montana electric retail customers and ~~approximately $1.3 million of costs related~~a higher property tax allocation to ~~generation portfolio modeling previously recovered through our electric~~FERC transmission customers (we do not have a property tax tracker ~~filings.~~for FERC jurisdictional purposes).

•In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 by the MPSC as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in the kWh sales lost due to energy efficiency programs through our supply tracker. Lost revenues were removed prospectively effective December 1, 2015.

•In October 2013, the MPSC concluded that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

In June 2016, we filed an appeal of the MPSC decision regarding the disallowance of portfolio modeling costs in Montana District Court. Also, in September 2016, we appealed the MPSC’s decisions regarding the disallowance of Colstrip Unit 4 replacement power costs and the modeling/planning costs in Montana District Court, arguing that these decisions were arbitrary and capricious, and violated Montana law.

In addition to our supply trackers, we file an annual property tax tracker with the MPSC for an automatic rate adjustment of our Montana property taxes, which allows recovery of 60 percent of the change in state and local taxes and fees. Adjusted rates are typically effective January 1st of each year. The MPSC identified concerns with the amount of annual increases proposed by the Montana Department of Revenue. In June 2017, the MPSC adopted new rules to establish minimum filing requirements for property tax trackers. Some of the proposed rules appear to be based on a narrow interpretation of the enabling statute and suggest that the MPSC will challenge the amount and allocation of these taxes to customers. Under the new rules, we may face obstacles to the same recovery that we now achieve. Any change in recovery of property taxes could have a material impact onrevised our ~~results of operations.~~

Additionally, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. In March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our costs in a future electric general rate filing.

Our ability to invest in additional generation is impacted by regulatory and public policy. Under PURPA, electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. Our requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs. In June 2017, the MPSC held a work session to discuss our application for approval of a revised tariff for standard QF rates for small ~~QFs. In July 2017, the MPSC issued an order establishing~~QFs (3 MW or less) to establish a maximum ~~10-year~~ contract length ~~with a rate adjustment after the first five~~of 15 years and ~~approving rates that do not include costs associated with the risk of~~a substantially lower rate for future ~~carbon dioxide emissions regulations.~~QF contracts. In this ~~same~~ order, the MPSC ~~indicated they will apply~~also applied the ~~10-year~~15-year contract term to ~~us for~~our future owned and contracted electric supply ~~resource transactions. We are evaluating the impact of this decision and have suspended~~resources. As a result, we terminated our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. This order may have a significant impact on our approach to meet our portfolio needs.

•In 2016, the MPSC disallowed replacement power costs from a 2013 outage at Colstrip Unit 4 requested in our electric tracker filings. We appealed the MPSC’s decision regarding the disallowance of Colstrip Unit 4 costs in Montana District Court, arguing that these decisions were arbitrary and capricious, and violated Montana law.

•In 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis our fixed costs that would otherwise have been collected in the kilowatt hour sales lost due to energy efficiency programs through our supply tracker. Recovery of lost revenues was terminated, prospectively, effective December 1, 2015.

•In 2013, the MPSC concluded that costs associated with a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

We have two significant dockets currently in process with the MPSC, including revisions to our statutory electric supply tracker and the adjustment of rates due the Tax Cuts and Jobs Act. Regarding the electric supply tracker, the MPSC advocated before the 2017 Montana Legislature for a revision to the statute that provided for mandatory recovery of our prudently incurred electric supply costs, and in April 2017, the Montana legislature passed HB 193, amending the statute. The revised statute gives the MPSC discretion whether to approve an electric supply cost adjustment mechanism. In July 2017, we filed a proposed electric PCCAM. Following the submission of intervenor testimony, the MPSC identified additional issues. The MPSC held a hearing during the second quarter of 2018. We cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. To the extent our energy supply costs are deemed imprudent by the MPSC, or the passage of HB 193 reduces our recovery or the timeliness of cash flows, the revised mechanism could adversely impact our results of operations and cash flows.

We also submitted a filing in March 2018 regarding the customer benefit of the Tax Cuts and Jobs Act, calculated using two alternative methods. We cannot predict how the MPSC may address this filing. If the MPSC determines the credits due to customers are higher than the expected reduction to income tax expense, this would result in an adverse impact to results of operations and cash flows.

FERC & Other Regulation

We must ~~also~~ comply with established reliability standards and requirements including Critical Infrastructure Protection (CIP) Reliability Standards, which apply to the North American Electric Reliability Corporation (NERC) functions in both the Midwest Reliability Organization for our South Dakota operations and Western Electricity Coordination Council for our Montana operations. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, audits, periodic data submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as approximately $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.

We are also subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.

We are subject to existing, and potential future, federal and state legislation. In the planning and management of our operations, we must address the effects of legislation within a regulatory framework. Federal and state laws can significantly impact our operations, whether it is new or revised statutes directly affecting the electric and gas industry, or other issues such as taxes.

We are subject to changing tax laws, regulations, and interpretations in multiple jurisdictions. Corporate tax reform continues to be a priority in the U.S. Changes to the U.S. tax system could have significant effects, positive and negative, on our effective tax rate, and on our deferred tax assets and liabilities. In addition, the timing of realization of certain tax benefits may be further delayed in the event of future extensions of bonus depreciation or expensing of capital investments and impact our ability to utilize our federal and state net operating loss carryforwards.

In addition, new or revised statutes can also materially affect our operations through impacting existing regulations or requiring new regulations. These changes are ongoing, and we cannot predict the future course of changes or the ultimate effect that this changing environment will have on us. Changes in laws, and the resulting regulations and tariffs and how they are implemented and interpreted, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our ability to invest in additional generation is impacted by PURPA, which requires electric utilities, with certain exceptions, to purchase energy and capacity from independent power producers that are QFs. Our requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs.

On June 22, 2016, ~~then-President Obama signed~~ the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act (SAFE PIPES Act), ~~which would reauthorize appropriations for~~was signed into law. The law prioritized the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) ~~safety programs through 2019. The law prioritizes PHMSA's~~ completion of outstanding ~~regulations. In addition, PHMSA~~regulations and proposed regulations to safety standards for natural gas transmission and gathering pipelines. The long-anticipated proposal could impose significant regulatory requirements for additional miles of natural gas pipeline, including pipelines constructed prior to 1970, which were previously exempt from PHMSA regulations related to pressure testing. It would also create a new "Moderate Consequence Area" category to expand safety protocols to pipelines in moderately populated areas. The rule also would codify the Integrity Verification Process (IVP) which is a process that will require companies to have reliable, traceable, verifiable, and complete records for pipelines in certain areas. The rule would establish a deadline for IVP completion that we will be required to meet. Costs incurred to comply with the proposed regulations may be material.

Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs and decrease system reliability, and adversely affect our business.

We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices. These resources are primarily intermittent, non-dispatchable generation that may be in excess of market prices during times of lower customer demand, and may not be able to generate electricity during peak times. These resources typically do not meet the requirements set forth in our supply plans for resource procurement. These requirements to purchase supply inconsistent with customer need may have several impacts, including increasing the likelihood and frequency that we will be required to reduce output from owned generation resources, which could increase costs to customers. In addition, this may impact our ability to invest in additional generation. Further, balancing load and generation from power generation on our system is challenging, and we expect that operational costs will increase as a result of integration of these intermittent, non-dispatchable generation projects. If we are unable to timely recover those costs through our power cost adjustment mechanism or otherwise, those increased costs may negatively affect our liquidity, results of operations, financial condition, and investment plans.

We are subject to extensive and changing environmental laws and regulations and potential environmental liabilities, which could have a material adverse effect on our liquidity and results of operations.

We are subject to extensive laws and regulations imposed by federal, state, and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations. We are also subject to judicial interpretations of those laws and regulations. We believe that we are in compliance with environmental regulatory requirements; however, possible future developments, such as more stringent environmental laws and regulations, ~~and~~ the timing of future enforcement proceedings that may be taken by environmental authorities, and judicial opinions regarding those laws and regulations, could affect our costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

In October 2015, the EPA published standards for states to implement to control GHG emissions from existing electric generating units. These standards are referred to as the ~~Clean Power Plan (CPP).~~CPP. We, along with a number of states and other parties, filed lawsuits against the EPA standards. ~~In February 2016,~~The EPA proposed to repeal the ~~U.S. Supreme Court entered~~CPP in October 2017, and in December 2017, issued an ~~order staying the implementation~~Advance Notice of Proposed Rulemaking (ANPR), soliciting information on systems of emission reduction that comply with EPA’s interpretation of the ~~CPP standards. In~~Clean Air Act, for a ~~separate proceeding, in January 2017,~~possible replacement of the CPP. Most recently, on July 9, 2018, the EPA ~~denied our administrative Petition for Reconsideration that had requested the EPA reconsider~~forwarded its proposed rule replacing the CPP ~~on the grounds that the CO~~₂ reductions in the CPP were substantially greater in Montana than in the proposed rule. In response, we filed a Petition for Review in the U.S. Court of Appeals for the District of Columbia in March 2017. Additional information regarding the CPP, the proposed reductions in South Dakota and Montana, and the pending litigation is included in Note 12 - Commitments and Contingencies to the ~~Condensed Consolidated Financial Statements.~~

~~There is uncertainty associated with the new EPA Administration and the timeframe~~OMB for actions that may be taken with regard to the existing and pending GHG-related regulations. In addition, in March 2017, President Trump signed an Executive Order instructing all federal agencies to review all regulations and other policies that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest. The order specifically identifies CPP as requiring review pursuant to this standard.interagency review. In light of ~~the Executive Order,~~these administrative actions, the future of the CPP regulations and associated guidance is uncertain. However, if the CPP is not repealed, survives the ~~Executive Order, the~~pending legal challenges and is implemented as written or if a replacement to the CPP is adopted with similar requirements, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are not recovered through regulated rates. Due to the pending litigation, the proposed repeal of the CPP, the ANPR, and the uncertainties in the state approaches, the ultimate timing and impact of the CPP or other GHG regulations on our operations cannot be determined with certainty at this time. Complying with the CO₂emission performance standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

Many of these environmental laws and regulations provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected.

Our electric and natural gas transmission and distribution operations involve numerous activities that may result in accidents, wildfires, system outages and other operating risks and costs that are unique to our industry.

Inherent in our electric and natural gas operations are a variety of hazards and operating risks, such as fires, electric contacts, leaks, explosions, catastrophic failures and mechanical problems. These risks could cause a loss of human life, significant damage to property, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others. Fires alleged to have been caused by our system could also expose us to significant damage claims on theories such as strict liability, negligence, gross negligence, trespass, inverse condemnation, and others. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire. For our natural gas lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks are significant. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Our owned and jointly owned electric generating facilities are subject to risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased power purchase costs and the inability to recover our investment.

Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs. In early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Colstrip Unit 4 returned to service in early 2014. As discussed above, we were not able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

Our investment in generating facilities is a long-lived asset. An early retirement of a unit before the end of the current estimated useful life or change in classification as held for use could have a material adverse impact on our results of operations. The timing of a change in estimated useful life may be dependent upon events out of our control. The costs associated with a retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs and environmental remediation costs, could be material and we have no assurance of recovery of these costs from customers.

As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down those units no later than July 2022. We do not have ownership in Units 1 and 2, and decisions regarding these units, including their shut down, were made by their respective owners. The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facilities agreement among the owners of all four units. When Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines. This reduction would be incorporated in our next general electric rate filing after the closure of Units 1 and 2, resulting in lower revenue credits to certain customers. In addition, the remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Two of the other joint owners have entered into settlements with regulators to accelerate the recovery of their investment in Colstrip Units 3 and 4 by using a depreciable life through 2027, but have not established a date for closure. Recovery of costs associated with the shut-down of the facility prior to the end of the useful life would be subject to MPSC approval.

Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. We and other joint owners are discussing new coal supply and transportation agreements, which anticipate expansion of the coal mine. This expansion requires environmental reviews and permitting. We cannot predict when or if those permits will be granted. Our coal supply and transportation agreements are with Western Energy Company (WeCo), a subsidiary of Westmoreland Coal Co. (Westmoreland), which notified its investors that it may seek Chapter 11 reorganization. While we cannot predict the ultimate effect of a Westmoreland or WeCo bankruptcy, we do not expect our existing coal supply and transportation agreements to be adversely affected and will continue negotiations for new agreements. If a new coal supply contract is not in place, we could continue under the current arrangement under mutual agreement, however the extraction costs would increase.

We also rely on a limited number of suppliers of coal for our electric generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.

Severe weather impacts, including but not limited to, thunderstorms, high winds, microbursts, wildfires, tornadoes and snow or ice storms can disrupt energy generation, transmission and distribution. We derive a significant portion of our energy supply from hydroelectric facilities, and the availability of water can significantly affect operations. Higher temperatures may decrease the Montana snowpack and impact the timing of run-off and may require us to purchase replacement power. Dry conditions also increase the threat of wildfires, which could threaten our communities and electric distribution and transmission lines and facilities. In addition, wildfires alleged to have been caused by our system could expose us to substantial property damage and other claims. Any damage caused as a result of wildfires could negatively impact our financial condition, results of operations or cash flows.

There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks.

We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms and would increase our borrowing costs. Higher interest rates on borrowings with variable interest rates could also have an adverse effect on our results of operations.

Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber (such as hacking and viruses) and physical security breaches and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. These assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including cyber attacks and other disruptive activities on third party facilities that are interconnected to us through the regional transmission grid or natural gas pipeline infrastructure.

Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.

We rely on information technology networks and systems to operate our critical infrastructure, engage in asset management activities, and process, transmit and store electronic information including customer and employee information. Further, our infrastructure, networks and systems are interconnected to external networks and neighboring critical infrastructure systems. Security breaches could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. Cyber or physical attacks, terrorist acts, or disruptive activities could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new facilities and capital improvements to existing facilities.

In addition, our information systems and those of our third-party vendors contain confidential information, including information about customers and employees. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject us to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. It could also reduce the value of proprietary information, and harm our reputation.

Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact.

These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for electricity, natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, and the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and ~~has~~may have the effect of inappropriately increasing rates generally and increasing rates for customers who do not own generation, unless retail rates are designed to ~~share the costs of the~~collect distribution grid costs across all customers in a manner that reflects the benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy.

~~Both decreasing~~Decreasing use per customer ~~driven~~(driven, for example, by appliance and lighting ~~efficiency~~efficiency) and the availability of cost-effective distributed generation, both put downward pressure on load growth. Our ~~electricity supply~~ resource ~~procurement~~ plan includes an expected load growth assumption of 0.8 percent annually, which reflects low customer and usage increases, offset in part by these ~~efficiency~~load reduction measures. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability

and the availability of generation, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial position could be adversely affected. Higher temperatures may also decrease the Montana snowpack, which may result in dry conditions and an increased threat of forest fires. Forest fires could threaten our communities and electric transmission lines and facilities. Any damage caused as a result of forest fires could negatively impact our financial condition, results of operations or cash flows. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs. There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events.

Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. Severe weather impacts our service territories, primarily through thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. We derive a significant portion of our power supply from hydroelectric facilities. Because of our heavy reliance on hydroelectric generation, snowpack, the timing of run-off, drought conditions, and the availability of water can significantly affect operations. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

We rely on information technology networks and systems to operate our critical infrastructure, engage in asset management activities, and process, transmit and store electronic information including customer and employee information. Further, our infrastructure, networks and systems are interconnected to external networks and neighboring critical infrastructure systems. Security breaches could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. In particular, any data loss or information security lapses resulting in the compromise of personal information or the improper use or disclosure of sensitive or classified information could result in claims, remediation costs, regulatory sanctions, loss of current and future contracts, and serious harm to our reputation.

We are subject to laws and rules issued by multiple government agencies concerning safeguarding and maintaining the confidentiality of our security, customer and business information. One of the agencies, NERC, has issued comprehensive regulations and standards surrounding the security of our operating systems, and is continually in the process of developing updated and additional requirements with which the utility industry must comply. The increasing promulgation of NERC rules and standards will increase our compliance costs and our exposure to the potential risk of violations of standards.

Security threats continue to evolve and adapt. Cyber or physical attacks, terrorist acts, or disruptive activities could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Our plans for future expansion through the acquisition of assets including natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.

Acquisitions include a number of risks, including but not limited to, regulatory approval, additional costs, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, and securing adequate capital to support the transaction. The regulatory process in which rates are determined may not result in rates that produce full recovery of our investments, or a reasonable rate of return. Uncertainties also exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

Our business strategy also includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas

investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

~~Our electric and natural gas operations involve numerous activities that may result in accidents and other operating risks and costs.~~

Inherent in our electric and natural gas operations are a variety of hazards and operating risks, such as fires, electric contacts, leaks, explosions and mechanical problems. These risks could cause a loss of human life, significant damage to property, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our natural gas transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks potentially is greater.

Our owned and jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facilities agreement among the owners of all four units. As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center, against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down these units no later than July 2022. We do not have ownership in Units 1 and 2, and decisions regarding these units, including their shut down, were made by their respective owners. When Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines. This reduction would be incorporated in our next general electric rate filing, resulting in lower revenue credits to certain customers.

In early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Colstrip Unit 4 returned to service in early 2014. As discussed above, we were not able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. These contracts are necessary for the long-term operation of the facility. Negotiation of a new coal supply contract anticipates environmental reviews and permitting, and we cannot predict when or if those permits will be granted. If a new coal supply contract is not in place, we could continue under the current arrangement for several years if the mining company agrees, however the extraction costs would increase.

~~We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.~~

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.

Poor investment performance of plan assets of our defined benefit pension and ~~post-retirement~~postretirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference. In addition, we are subject to price escalation risk with one of ~~our~~the largest QF contracts.

As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. This obligation is reflected in the electric QF liability, which reflects the unrecoverable costs associated with these specific QF contracts per the stipulation. The annual minimum energy requirement is achievable under normal QF operations of these facilities, including normal periods of planned and forced outages. However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any QF shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted QF rates.

In addition, we are subject to price escalation risk with one of ~~our~~the largest contracts included in the electric QF ~~contracts~~liability due to variable contract terms. In ~~estimating our~~recording the electric QF liability, we ~~have~~ estimated an annual escalation rate of three percent over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds three percent, our results of operations, cash flows and financial position could be adversely affected.

ITEM 6. EXHIBITS -

(a) Exhibits

Exhibit 31.1—Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 31.2—Certification of chief financial officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



			NorthWestern Corporation
Date:	July ~~26, 2017~~20, 2018	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer



~~EXHIBIT INDEX~~



~~Exhibit~~ ~~Number~~		~~Description~~
*31.1		~~Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.~~
*31.2		~~Certification of chief financial officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.~~
*32.1		~~Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.~~
*32.2		~~Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.~~
*101.INS		~~XBRL Instance Document~~
*101.SCH		~~XBRL Taxonomy Extension Schema Document~~
*101.CAL		~~XBRL Taxonomy Extension Calculation Linkbase Document~~
*101.DEF		~~XBRL Taxonomy Extension Definition Linkbase Document~~
*101.LAB		~~XBRL Taxonomy Label Linkbase Document~~
*101.PRE		~~XBRL Taxonomy Extension Presentation Linkbase Document~~

~~_________________________~~


*	~~Filed herewith~~



	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
June 30, 2017
Restricted cash	$	5,354	$	—	$	—	$	—	$	5,354
Rabbi trust investments	29,012		—		—		—		29,012
Total	$	34,366	$	—	$	—	$	—	$	34,366

December 31, 2016
Restricted cash	$	4,164	$	—	$	—	$	—	$	4,164
Rabbi trust investments	25,064		—		—		—		25,064
Total	$	29,228	$	—	$	—	$	—	$	29,228



	June 30, 2017			December 31, 2016
	Carrying Amount	Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	1,793,797	$	1,898,482	$	1,793,338	$	1,852,052



Amount outstanding at period end	$	303.7
Daily average amount outstanding	$	223.2
Maximum amount outstanding	$	303.7

Location of amount reclassified from AOCL to Income

Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2017

Interest rate contracts

Interest Expense