NORTHWESTERN CORP - FORM 10-Q

Attached files

Attached files

Stock widget

Investing forum

NORTHWESTERN CORP Reports

Also read

file	filename
EX-31.2 - EXHIBIT 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER - NORTHWESTERN CORP	ex312certificationq22017.htm
EX-32.2 - EXHIBIT 32.2 CERTIFICATION OF BRIAN B. BIRD PURSUANT TO SECTION 906 - NORTHWESTERN CORP	ex322certificationq22017.htm
EX-32.1 - EXHIBIT 32.1 CERTIFICATION OF ROBERT C. ROWE PURSUANT TO SECTION 906 - NORTHWESTERN CORP	ex321certificationq22017.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - NORTHWESTERN CORP	ex311certificationq22017.htm

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

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

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 shares outstanding at July 21, 2017

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 and 2016	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2017 and 2016	5
	Condensed Consolidated Balance Sheets — June 30, 2017 and December 31, 2016	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2017 and 2016	7
	Condensed Consolidated Statements of Shareholders' Equity — Six Months Ended June 30, 2017 and 2016	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	53
Item 4.	Controls and Procedures	54
PART II. OTHER INFORMATION		55
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
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,
	2017			2016			2017			2016
Revenues
Electric	$	233,866		$	248,403		$	500,105		$	489,745
Gas	49,993			44,717			151,066			135,914
Total Revenues	283,859			293,120			651,171			625,659
Operating Expenses
Cost of sales	84,000			81,693			203,817			197,127
Operating, general and administrative	75,188			72,579			156,150			152,440
Property and other taxes	39,481			35,208			79,409			70,629
Depreciation and depletion	41,495			39,898			82,956			79,788
Total Operating Expenses	240,164			229,378			522,332			499,984
Operating Income	43,695			63,742			128,839			125,675
Interest Expense, net	(23,408		)	(26,421		)	(46,808		)	(50,930		)
Other Income	2,123			1,195			3,623			4,297
Income Before Income Taxes	22,410			38,516			85,654			79,042
Income Tax Expense	(580		)	(2,947		)	(7,257		)	(3,606		)
Net Income	$	21,830		$	35,569		$	78,397		$	75,436

Average Common Shares Outstanding	48,451			48,309			48,418			48,275
Basic Earnings per Average Common Share	$	0.45		$	0.74		$	1.62		$	1.57
Diluted Earnings per Average Common Share	$	0.44		$	0.73		$	1.61		$	1.55
Dividends Declared per Common Share	$	0.525		$	0.50		$	1.05		$	1.00

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,
	2017			2016		2017			2016
Net Income	$	21,830		$	35,569	$	78,397		75,436
Other comprehensive income (loss), net of tax:
Foreign currency translation	(104		)	8		(53		)	(110		)
Reclassification of net losses on derivative instruments	93			37		186			74
Total Other Comprehensive (Loss) Income	(11		)	45		133			(36		)
Comprehensive Income	$	21,819		$	35,614	$	78,530		$	75,400

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
ASSETS
Current Assets:
Cash and cash equivalents	$	16,859		$	5,079
Restricted cash	5,608			4,426
Accounts receivable, net	123,925			159,556
Inventories	50,599			49,206
Regulatory assets	35,898			50,041
Other	15,128			11,887
Total current assets	248,017			280,195
Property, plant, and equipment, net	4,261,983			4,214,892
Goodwill	357,586			357,586
Regulatory assets	641,720			602,943
Other noncurrent assets	47,626			43,705
Total Assets	$	5,556,932		$	5,499,321
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	2,053			$	1,979
Short-term borrowings	303,658			300,811
Accounts payable	55,530			79,311
Accrued expenses	200,517			205,370
Regulatory liabilities	16,670			26,361
Total current liabilities	578,428			613,832
Long-term capital leases	23,320			24,346
Long-term debt	1,793,797			1,793,338
Deferred income taxes	615,510			575,582
Noncurrent regulatory liabilities	406,305			396,225
Other noncurrent liabilities	430,975			419,771
Total Liabilities	3,848,335			3,823,094
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
Treasury stock at cost	(96,689		)	(95,769		)
Paid-in capital	1,389,426			1,384,271
Retained earnings	424,920			396,919
Accumulated other comprehensive loss	(9,581		)	(9,714		)
Total Shareholders' Equity	1,708,597			1,676,227
Total Liabilities and Shareholders' Equity	$	5,556,932		$	5,499,321

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Six Months Ended June 30,
	2017			2016
OPERATING ACTIVITIES:
Net income	$	78,397		$	75,436
Items not affecting cash:
Depreciation and depletion	82,956			79,788
Amortization of debt issue costs, discount and deferred hedge gain	2,392			1,987
Stock-based compensation costs	3,826			3,361
Equity portion of allowance for funds used during construction	(2,298		)	(1,608		)
(Gain) loss on disposition of assets	(401		)	1,054
Deferred income taxes	6,320			3,722
Changes in current assets and liabilities:
Restricted cash	(1,182		)	46
Accounts receivable	35,631			38,577
Inventories	(1,393		)	3,535
Other current assets	(3,241		)	(7,365		)
Accounts payable	(19,788		)	(17,595		)
Accrued expenses	(4,853		)	786
Regulatory assets	14,143			10,865
Regulatory liabilities	(9,691		)	(55,614		)
Other noncurrent assets	(6,781		)	(3,099		)
Other noncurrent liabilities	3,767			7,118
Cash Provided by Operating Activities	177,804			140,994
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(119,123		)	(121,246		)
Proceeds from sale of assets	379			137
Cash Used in Investing Activities	(118,744		)	(121,109		)
FINANCING ACTIVITIES:
Treasury stock activity	411			(1,614		)
Dividends on common stock	(50,396		)	(47,865		)
Issuance of long-term debt	—			60,000
Repayments on long-term debt	—			(55,000		)
Issuances of short-term borrowings, net	2,847			26,932
Financing costs	(142		)	(5,349		)
Cash Used in Financing Activities	(47,280		)	(22,896		)
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
Supplemental Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	61		$	(2,922	)
Interest	40,280			42,861
Significant non-cash transactions:
Capital expenditures included in accounts payable	9,776			11,054

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

Balance at December 31, 2016	51,958	3,626		$	520	$	1,384,271		$	(95,769	)	$	396,919		$	(9,714	)	$	1,676,227

Net income	—	—		—		—			—			78,397			—			78,397
Foreign currency translation adjustment	—	—		—		—			—			—			(53		)	(53		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—		—		—			—			—			186			186
Stock-based compensation	133	(6	)	1		5,155			(920		)	—			—			4,236
Dividends on common stock ($1.05 per share)	—	—		—		—			—			(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

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 natural gas to approximately 709,600 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, 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. 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.

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 (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 (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 million through 2024.

(2) New Accounting Standards

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 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 this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method requires 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 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 revenue recognition.

Retirement Benefits - In March 2017, the FASB issued new guidance on the presentation of net periodic costs related to benefit plans. The new guidance requires the service cost component of net periodic benefit cost to be included within operating income within the same line as other compensation expenses. All other components of net periodic costs must be outside of operating income. In addition, the updated guidance permits only the service cost component 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 of the aggregate net periodic benefit costs on the income statement within operating income, and which permits all components of net periodic costs to be capitalized.

This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be applied retrospectively for the presentation of the various components of net periodic costs and prospectively for the change in eligible costs to be capitalized. We have not yet fully determined the impacts of adoption of the standard, but expect that 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.

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 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. 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 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.

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. 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.

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. 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.

(3) Regulatory Matters

Montana Natural Gas General Rate Filing

In June 2017, we reached a settlement agreement with intervenors in our natural gas rate case. This settlement included an overall increase in delivery services 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 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 in base rates of fields acquired 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 our supply tracker.

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.

QF Decision

Under the Public Utility Regulatory Policies Act (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 June 2017 to discuss our application for approval 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 costs associated with the risk of future carbon dioxide emissions regulations. We expect this will result in substantially lower rates for these contracts. In this same order, the MPSC indicated they will apply the 10-year contract term 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.

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 the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May 2017, the MPSC issued a Notice of Commission Action (NCA) initiating 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 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 comments 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 the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's May and July 2017 NCAs, and the Montana-Dakota Utilities (MDU) Montana adjustment 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 retroactive to the effective date of HB 193.

Electric Tracker Open Dockets - 2015/2016 - 2016/2017 - 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, the MPSC consolidated the dockets for the 2015/2016 and 2016/2017 tracker periods, which are approved on an interim basis. The MPSC has not established a schedule regarding these remaining open dockets under the prior statutory tracker.

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.

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 in the Consolidated Docket and 2015 Tracker, resulting 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 the disallowance of replacement power costs from a 2013 outage at Colstrip Unit 4 and the modeling/planning costs, arguing that these decisions were 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 within the next 12 months. We expect a decision in the 2015 Tracker appeal in the next 12 to 18 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 amount we are allowed to recover in hydro generation rates by approximately $1.2 million. In addition, in the final order, 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 annual report with the MPSC regarding 2016 results, which indicates we earned less than our authorized rate of return. At the same time, we also submitted a filing to the MPSC responsive to the hydro compliance order, indicating we do not expect to file an electric rate case in 2017 based on a 2016 test year. However, we indicated we expect to file a general electric rate case in 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, 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.

FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS)

In May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying 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 (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had cumulative deferred revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit (D.C. Circuit). 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.

(4) Income Taxes

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.

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,
	2017					2016
Income Before Income Taxes	$	22,410				$	38,516

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

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

Income Tax Expense	$	580		2.6	%	$	2,947		7.7	%



	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.

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 million as of June 30, 2017, including approximately $66.7 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2017 we recognized $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 of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of June 30, 2017 and December 31, 2016, we had $1.0 million and $0.7 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) Goodwill

We completed our annual goodwill impairment test as of April 1, 2017, 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. Goodwill by segment is as follows for both June 30, 2017 and December 31, 2016 (in thousands):



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

(6) 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
	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	$	(53	)	$	—		$	(53	)	$	(110	)	$	—		$	(110	)
Reclassification of net losses on derivative instruments	306			(120		)	186			124			(50		)	74
Other comprehensive income (loss)	$	253		$	(120	)	$	133		$	14		$	(50	)	$	(36	)

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



	June 30, 2017			December 31, 2016
Foreign currency translation	$	1,327		$	1,380
Derivative instruments designated as cash flow hedges	(10,166		)	(10,352		)
Postretirement medical plans	(742		)	(742		)
Accumulated other comprehensive loss	$	(9,581	)	$	(9,714	)

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



		Three Months Ended
		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
Beginning balance		$	(10,259	)	$	(742	)	$	1,431		(9,570		)
Other comprehensive loss before reclassifications		—			—			(104		)	(104		)
Amounts reclassified from AOCL	Interest Expense	93			—			—			93
Net current-period other comprehensive income (loss)		93			—			(104		)	(11		)
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)



		Three Months Ended
		June 30, 2016
	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		)
Other comprehensive income before reclassifications		—			—			8		8
Amounts reclassified from AOCL	Interest Expense	37			—			—		37
Net current-period other comprehensive income		37			—			8		45
Ending balance		$	(8,940	)	$	(937	)	$	1,245	$	(8,632	)



		Six Months Ended
		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
Beginning balance		$	(10,352	)	(742		)	$	1,380		(9,714		)
Other comprehensive loss before reclassifications		—			—			(53		)	(53		)
Amounts reclassified from AOCL	Interest Expense	186			—			—			186
Net current-period other comprehensive income (loss)		186			—			(53		)	133
Ending balance		$	(10,166	)	$	(742	)	$	1,327		$	(9,581	)



		Six Months Ended
		June 30, 2016
	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		)
Other comprehensive loss before reclassifications		—			—			(110		)	(110		)
Amounts reclassified from AOCL	Interest Expense	74			—			—			74
Net current-period other comprehensive income (loss)		74			—			(110		)	(36		)
Ending balance		$	(8,940	)	$	(937	)	$	1,245		$	(8,632	)

(7) Risk Management and Hedging 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, we may use interest rate swaps 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 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):

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 of our common stock and actively traded mutual funds with quoted prices in active markets.

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
Operating revenues	233,866			$	49,993		$	—		$	—	$	283,859
Cost of sales	70,146			13,854			—			—		84,000
Gross margin	163,720			36,139			—			—		199,859
Operating, general and administrative	54,086			20,206			896			—		75,188
Property and other taxes	30,909			8,569			3			—		39,481
Depreciation and depletion	34,105			7,382			8			—		41,495
Operating income (loss)	44,620			(18		)	(907		)	—		43,695
Interest expense	(21,064		)	(1,500		)	(844		)	—		(23,408		)
Other income	917			489			717			—		2,123
Income tax (expense) benefit	(523		)	817			(874		)	—		(580		)
Net income (loss)	$	23,950		$	(212	)	$	(1,908	)	$	—	$	21,830
Total assets	$	4,439,694		$	1,114,426		$	2,812		—		$	5,556,932
Capital expenditures	$	55,995		$	11,609		$	—		—		$	67,604



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
Operating revenues	$	489,745		$	135,914		$	—		$	—	$	625,659
Cost of sales	155,789			41,338			—			—		197,127
Gross margin	333,956			94,576			—			—		428,532
Operating, general and administrative	107,011			42,497			2,932			—		152,440
Property and other taxes	54,751			15,872			6			—		70,629
Depreciation and depletion	65,065			14,707			16			—		79,788
Operating income (loss)	107,129			21,500			(2,954		)	—		125,675
Interest expense	(46,174		)	(3,769		)	(987		)	—		(50,930		)
Other income	1,154			580			2,563			—		4,297
Income tax (expense) benefit (1)	(4,346		)	(1,743		)	2,483			—		(3,606		)
Net income (1)	$	57,763		$	16,568		$	1,105		$	—	$	75,436
Total assets	$	4,221,293		$	1,080,065		$	6,248		$	—	$	5,307,606
Capital expenditures	$	99,563		$	21,683		$	—		$	—	$	121,246

______________

(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 of January 1, 2016, which resulted in an increase in net income for the six months ended June 30, 2016 above.

(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
	June 30, 2017	June 30, 2016
Basic computation	48,450,639	48,308,656
Dilutive effect of:
Performance share awards (1)	130,772	76,877

Diluted computation	48,581,411	48,385,533



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

Diluted computation	48,547,751	48,352,219

_______

(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

Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands):



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



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

(12) Commitments and Contingencies



ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, 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 million to $32.6 million. As of June 30, 2017, we have a reserve of approximately $30.6 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 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, the reserve for remediation costs at this site is approximately $10.4 million, and we estimate that approximately $5.9 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 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.

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 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 (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 was instructed 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 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 emission performance standards for existing electric utility steam generating units and NGCC units.

Under the CPP, states may develop implementation plans for affected units to meet the individual state GHG emission reduction targets established in the CPP or may adopt a federal plan. The CPP may require reductions in CO₂ 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 were filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), including an appeal by us filed on October 23, 2015. The United States Supreme Court (Supreme Court) issued a stay of the CPP on February 9, 2016 pending resolution of the appeals by the D.C. Circuit and possibly the Supreme Court. Oral argument on the case was held in September 2016. In April 2017, the D.C. Circuit granted the EPA's request to hold the case in abeyance pursuant to the Executive Order, but only for a period of sixty days.

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 what, if any, action the D.C. Circuit may take in either of these two cases before the EPA takes action to address the CPP.

If the CPP survives the Executive Order, the legal challenges described above, and is implemented as written, 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 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 additional 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. On March 13, 2017, we filed a Petition for Review of these amendments with the D.C. Circuit. On March 15, 2017, our petition was consolidated with other petitions challenging the final rule.

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 until there is a definitive judicial decision or administrative action by the EPA to withdraw or significantly change 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 solar QF developer with which we began negotiating in early 2016 to purchase capacity and energy at our avoided cost under the QF-1 option 1(a) tariff standard rates in accordance with PURPA as implemented by the FERC and the MPSC.

On June 16, 2016, however, the MPSC entered a Notice of Commission Action (MPSC Notice) suspending the availability of QF-1 option 1(a) 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 QF had submitted a signed power purchase agreement and had executed an interconnection agreement. PNWS had not obtained interconnection agreements for any of its projects as of June 16, 2016 and, based on the MPSC Notice and subsequent July 25, 2016 Order 7500 of like effect from the MPSC, we discontinued further negotiations with PNWS.

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 on 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 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 the MPSC could consider related issues that might bear on the issues raised 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 to the MPSC for approval of its first four solar projects, PNWS agreed to drop its damage claims related to the other 17 projects. If the MPSC approves the four projects, PNWS will also drop its damage claims related to those four projects. If the MPSC does not approve the four projects, PNWS will be able

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 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 lawsuit and intend to vigorously defend those that have not been resolved by the partial settlement. This matter is in the initial stages, and we cannot predict an outcome or estimate the amount or range of loss that would be associated with an adverse result on the remaining claims.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana filed a complaint on remand with the Montana First Judicial District Court (State District Court), naming us, along with 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 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 rivers which were navigable and that the State held title to the riverbeds. Subsequently, in June 2008, the State District Court awarded the State compensation 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, the United States Supreme Court granted Talen's petition to review the Montana Supreme Court decision. The United States Supreme Court issued an opinion 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 and second in relying on present day recreational use of the rivers. The United States Supreme Court also considered the navigability of what it referred to as the Great Falls Reach and concluded, at least from the head of the first waterfall to the foot of the last, that the Great Falls Reach 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 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), and Talen consented to our removal. On April 27, 2016, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with 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. 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

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 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.

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 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.

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



HOW WE PERFORMED AGAINST OUR SECOND QUARTER 2016 RESULTS



	Quarter-over-Quarter Change

Gross Margin by Segment⁽¹⁾
Electric	$(12.4)M	ê	(7.0)%
Natural Gas	$0.9M	é	2.6%


Operating Income	$(20.0)M	ê	(31.5)%


Net Income	$(13.7)M	ê	(38.6)%


EPS (Diluted)	$(0.29)	ê	(39.7)%

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



SIGNIFICANT DEVELOPMENTS IN Q2 2017



	Ÿ	A decrease in net income of $13.7 million, primarily due to the recognition in 2016 of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings, lower retail electric volumes and higher operating expenses in 2017.

Following is a brief overview of significant items for 2017.



SIGNIFICANT TRENDS AND REGULATION

Montana Natural Gas General Rate Filing

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 June 2017 to discuss our application for approval 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 costs associated with the risk of potential future carbon dioxide emissions regulations. We expect this will result in substantially lower rates for these contracts. In this same order, the MPSC indicated they will apply the 10-year contract term 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.

Montana House Bill 193 / Electric and Natural Gas Tracker Filings

House Bill 193 - 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 2017, the MPSC issued a NCA initiating 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 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 comments 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 the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's May and July 2017 NCAs and the MDU Montana adjustment 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 retroactive to the effective date of HB 193.



RESULTS OF OPERATIONS

Our consolidated results include the results of our reportable business segments, which are primarily engaged in the electric and natural gas business. 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. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation and depletion from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. 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. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

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 Compared with the Three Months Ended June 30, 2016



	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	)%



	Three Months Ended June 30,
	2017		2016		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	70.1	$	72.2	$	(2.1	)	(2.9	)%
Natural Gas	13.9		9.5		4.4			46.3
Total Cost of Sales	$	84.0	$	81.7	$	2.3		2.8	%



	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	)%

Primary components of the change in gross margin 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	)

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


•	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 in electric retail volumes due primarily to milder spring weather partly offset by customer growth;


•	An adjustment in 2016 in 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:


•	An increase in natural gas retail volumes due primarily to colder spring 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 in QF related supply costs based on actual QF pricing and output.

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


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


•	An increase in natural gas production gathering fees is offset by an increase in operating expenses.



	Three Months Ended June 30,
	2017		2016		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	75.2	$	72.6	$	2.6	3.6	%
Property and other taxes	39.5		35.2		4.3		12.2
Depreciation and depletion	41.5		39.9		1.6		4.0
	$	156.2	$	147.7	$	8.5	5.8	%

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



	Operating, General & Administrative Expenses
	2017 vs. 2016
	(in millions)
Labor	$	0.9
Bad debt expense	0.6
Maintenance costs	0.5
Non-employee directors deferred compensation	0.4
Natural gas production gathering expense	0.4
Other	(0.2		)
Increase in Operating, General & Administrative Expenses	$	2.6

The increase in operating, general and administrative expenses is primarily due to the following:


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


•	Higher bad debt 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).

Property and other taxes were $39.5 million for the three months ended June 30, 2017, as compared with $35.2 million in the same period of 2016. 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 recover these amounts. Our Montana property tax tracker mechanism currently allows for the recovery of

approximately 60% 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.

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

Consolidated operating income for the three months ended June 30, 2017 was $43.7 million as compared with $63.7 million in the same period of 2016. This decrease was primarily due to the decrease in gross margin driven by the recognition in 2016 of deferred revenue as a result of a MPSC final order, lower electric retail volumes and higher property taxes.

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

disallowance along with the debt refinancing of the Pollution Control Revenue Refunding Bonds during the third quarter of 2016.

Consolidated other income for the three months ended June 30, 2017, was $2.1 million, as compared with $1.2 million in the same period of 2016. This increase was primarily due to higher capitalization of allowance for funds used during construction (AFUDC) and a $0.4 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding decrease to operating, general and administrative expenses).

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

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



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

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

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

Income Tax Expense	$	0.6		2.6	%	$	2.9		7.7	%

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 was $21.8 million as compared with $35.6 million for the same period in 2016. This decrease was primarily due to the recognition in 2016 of deferred revenue as a result of a MPSC final order in our tracker filings, lower electric retail volumes and higher operating expenses as discussed above, partly offset by lower interest and income tax expense.

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



	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	%



	Six Months Ended June 30,
	2017		2016		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	344.6	$	333.9	$	10.7	3.2	%
Natural Gas	102.8		94.6		8.2		8.7
Total Gross Margin	$	447.4	$	428.5	$	18.9	4.4	%

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



	Gross Margin 2017 vs. 2016
	(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 transmission	0.2
2016 Lost revenue adjustment mechanism	(14.2		)
Natural gas production	(0.7		)
Other	1.3
Change in Gross Margin Impacting Net Income	12.2

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	6.3
Gas production gathering fees	0.4
Change in Items Offset Within Net Income	6.7
Increase in Gross Margin	$	18.9

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


•	The inclusion in our 2016 results of the MPSC disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;


•	An increase in natural gas retail volumes due primarily to colder winter and spring 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.

These increases were partly offset by:


•	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; and


•	Lower 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.

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


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


•	An increase in natural gas production gathering fees is offset by an increase in operating expenses.



	Six Months Ended June 30,
	2017		2016		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	156.2	$	152.4	$	3.8	2.5	%
Property and other taxes	79.4		70.6		8.8		12.5
Depreciation and depletion	83.0		79.8		3.2		4.0
	$	318.6	$	302.8	$	15.8	5.2	%

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



	Operating, General & Administrative Expenses
	2017 vs. 2016
	(in millions)
Maintenance costs	$	2.0
Bad debt expense	1.9
Labor	1.4
Natural gas production gathering expense	0.4
Non-employee directors deferred compensation	(1.3		)
Insurance reserves	(1.0		)
Other	0.4
Increase in Operating, General & Administrative Expenses	$	3.8

The increase in operating, general and administrative expenses is primarily due to the following:


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


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


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


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

These increases were offset in part by:


•	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.

Property and other taxes were $79.4 million for the six months ended June 30, 2017, as compared with $70.6 million in the same period of 2016. 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 million on an annual basis in 2017 as compared with 2016.

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

Consolidated operating income for the six months ended June 30, 2017 was $128.8 million as compared with $125.7 million in the same period of 2016. This increase was primarily due to the increase in gross margin as discussed above, offset in part by higher operating expenses.

Consolidated interest expense for the six months ended June 30, 2017 was $46.8 million, as compared with $50.9 million in the same period of 2016. 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.

Consolidated other income for the six months ended June 30, 2017, was $3.6 million, as compared with $4.3 million in the same period of 2016. This decrease was primarily due to 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 offset by a corresponding decrease to operating, general and administrative expenses). This decrease was offset in part by higher capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, 2017 was $7.3 million, as compared with $3.6 million in the same period of 2016. Our effective tax rate for the six months ended June 30, 2017 was 8.5% as compared with 4.6% 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.

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



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

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

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

Income Tax Expense	$	7.3		8.5	%	$	3.6		4.6	%

Consolidated net income for the six months ended June 30, 2017 was $78.4 million as compared with $75.4 million for the same period in 2016. This increase was primarily due to improved gross margin as a result of favorable weather and lower interest expense, partly offset by higher operating and income tax expense.

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 in the Southwest Power Pool, where we buy and sell wholesale energy and reserves through the operation of a single, consolidated balancing authority. This line also includes miscellaneous electric revenues.

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



	Results
	2017		2016		Change			% Change
	(dollars in millions)
Retail revenues	$	196.0	$	200.6	$	(4.6	)	(2.3	)%
Regulatory amortization	4.5		16.1		(11.6		)	(72.0	)
Total retail revenues	200.5		216.7		(16.2		)	(7.5	)
Transmission	13.1		12.7		0.4			3.1
Ancillary services	0.4		0.4		—			—
Wholesale and other	19.9		18.6		1.3			7.0
Total Revenues	233.9		248.4		(14.5		)	(5.8	)
Total Cost of Sales	70.1		72.2		(2.1		)	(2.9	)
Gross Margin	$	163.8	$	176.2	$	(12.4	)	(7.0	)%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2017		2016		2017	2016	2017	2016
	(in thousands)
Montana	$	59,740	$	63,044	503	522	294,721	290,743
South Dakota	12,832		12,640		110	113	50,158	49,946
Residential	72,572		75,684		613	635	344,879	340,689
Montana	83,028		85,611		764	775	66,277	65,421
South Dakota	21,400		20,706		230	231	12,687	12,642
Commercial	104,428		106,317		994	1,006	78,964	78,063
Industrial	10,087		9,772		554	538	75	73
Other	8,920		8,841		51	50	6,205	6,222
Total Retail Electric	$	196,007	$	200,614	2,212	2,229	430,123	425,047



	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:
	2017	2016	Historic Average	2016	Historic Average
Montana	1,061	973	1,223	9% colder	13% warmer
South Dakota	1,321	1,246	1,410	6% colder	6% warmer

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



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

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	2.9
Change in Items Offset Within Net Income	2.9
Decrease in Gross Margin	$	(12.4	)

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


•	The recognition in 2016 of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings;


•	A decrease in electric residential and commercial retail volumes due primarily to milder spring weather partly offset by growth in our residential and industrial customers; 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


•	A decrease in QF related supply costs based on actual QF pricing and output.

The increase in revenues for property taxes included in trackers is offset by increased property tax expense with no impact to net income.

The change in regulatory amortization revenue includes the recognition of deferred revenue in 2016, as discussed above and timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers. These timing differences have 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 Compared with the Six Months Ended June 30, 2016



	Results
	2017			2016		Change			% Change
	(dollars in millions)
Retail revenues	$	430.7		$	410.8	$	19.9		4.8	%
Regulatory amortization	(0.7		)	12.7		(13.4		)	(105.5	)
Total retail revenues	430.0			423.5		6.5			1.5
Transmission	25.5			25.3		0.2			0.8
Ancillary services	0.8			0.8		—			—
Wholesale and other	43.8			40.1		3.7			9.2
Total Revenues	500.1			489.7		10.4			2.1
Total Cost of Sales	155.5			155.8		(0.3		)	(0.2	)
Gross Margin	$	344.6		$	333.9	$	10.7		3.2	%



	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			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:
	2017	2016	Historic Average	2016	Historic Average
Montana	4,437	3,852	4,496	15% colder	1% warmer
South Dakota	5,211	4,920	5,535	6% colder	6% warmer

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



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

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	4.8
Change in Items Offset Within Net Income	4.8
Increase in Gross Margin	$	10.7

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


•	The inclusion in 2016 of the MPSC disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;


•	An increase in residential and commercial retail volumes due primarily to colder winter 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; and


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

These increases were partly offset by the recognition in 2016 of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings. In addition, the increase in revenues for property taxes included in trackers is offset by increased property tax expense with no impact to net income.

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 Compared with the Three Months Ended June 30, 2016



	Results
	2017		2016		Change			% Change
	(dollars in millions)
Retail revenues	$	38.2	$	33.1	$	5.1		15.4	%
Regulatory amortization	2.0		2.4		(0.4		)	(16.7	)
Total retail revenues	40.2		35.5		4.7			13.2
Wholesale and other	9.8		9.2		0.6			6.5
Total Revenues	50.0		44.7		5.3			11.9
Total Cost of Sales	13.9		9.5		4.4			46.3
Gross Margin	$	36.1	$	35.2	$	0.9		2.6	%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2017		2016		2017	2016	2017	2016
	(in thousands)
Montana	$	16,507	$	14,228	1,981	1,765	170,311	168,006
South Dakota	4,297		3,980		512	487	39,436	39,088
Nebraska	4,104		3,425		436	420	37,192	37,034
Residential	24,908		21,633		2,929	2,672	246,939	244,128
Montana	8,211		7,097		1,034	922	23,548	23,238
South Dakota	2,750		2,343		521	516	6,536	6,421
Nebraska	2,057		1,673		342	336	4,765	4,707
Commercial	13,018		11,113		1,897	1,774	34,849	34,366
Industrial	156		153		21	22	252	259
Other	165		190		24	30	158	158
Total Retail Gas	$	38,247	$	33,089	4,871	4,498	282,198	278,911



	Heating Degree Days			2017 as compared with:
	2017	2016	Historic Average	2016	Historic Average
Montana	1,133	1,011	1,265	12% colder	10% warmer
South Dakota	1,321	1,246	1,410	6% colder	6% warmer
Nebraska	1,028	1,038	1,154	1% warmer	11% warmer

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



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

Gross Margin Items Offset in Operating Expenses
Production gathering fees	0.4
Property taxes recovered in trackers	0.3
Change in Items Offset Within Net Income	0.7
Increase in Gross Margin	$	0.9

Gross margin for items impacting net income increased $0.2 million due to an increase in retail volumes 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 rates, partly offset by a $0.3 million increase in overhead fees.

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


•	An increase in production gathering fees is offset by an increase in operating expenses; and


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

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 Compared with the Six Months Ended June 30, 2016



	Results
	2017			2016			Change			% Change
	(dollars in millions)
Retail revenues	$	137.1		$	117.0		$	20.1		17.2	%
Regulatory amortization	(6.6		)	(0.6		)	(6.0		)	1,000.0
Total retail revenues	130.5			116.4			14.1			12.1
Wholesale and other	20.6			19.5			1.1			5.6
Total Revenues	151.1			135.9			15.2			11.2
Total Cost of Sales	48.3			41.3			7.0			16.9
Gross Margin	$	102.8		$	94.6		$	8.2		8.7	%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2017		2016		2017	2016	2017	2016
	(in thousands)
Montana	$	60,275	$	50,553	7,903	6,722	170,238	167,895
South Dakota	15,101		14,128		2,027	1,874	39,563	39,219
Nebraska	13,134		11,244		1,684	1,558	37,332	37,172
Residential	88,510		75,925		11,614	10,154	247,133	244,286
Montana	30,144		24,982		4,125	3,446	23,550	23,231
South Dakota	10,179		8,952		1,856	1,771	6,558	6,442
Nebraska	6,969		5,946		1,216	1,136	4,793	4,727
Commercial	47,292		39,880		7,197	6,353	34,901	34,400
Industrial	662		590		93	85	254	261
Other	612		576		95	92	158	158
Total Retail Gas	$	137,076	$	116,971	18,999	16,684	282,446	279,105



	Heating Degree Days			2017 as compared with:
	2017	2016	Historic Average	2016	Historic Average
Montana	4,601	3,998	4,509	15% colder	2% colder
South Dakota	5,211	4,920	5,535	6% colder	6% warmer
Nebraska	4,110	3,989	4,578	3% colder	10% warmer

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



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

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	1.5
Production gathering fees	0.4
Change in Items Offset Within Net Income	1.9
Increase in Gross Margin	$	8.2

Gross margin for items impacting net income increased $6.3 million from an increase in retail volumes due to colder winter and spring 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.

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


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


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

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. 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 is provided by internal cash flows, the sale of commercial paper and use of our revolving credit facility. We utilize our short-term borrowings and / or revolver availability 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 borrowings may also be used to temporarily fund utility capital requirements. As of June 30, 2017, our total net liquidity was approximately $113.2 million, including $16.9 million of cash and $96.3 million of revolving credit facility availability. Revolving credit facility availability was $119.3 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

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. Montana law defining our current electric tracking mechanism was repealed effective July 1, 2017, and the MPSC has outlined a process for implementing a replacement mechanism. We expect 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.

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

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 impact our trade credit availability. Fitch Ratings (Fitch), 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, our current ratings with these agencies are as follows:



	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A	A-	F2	Stable
Moody’s (1)	A2	Baa1	Prime-2	Negative
S&P	A-	BBB	A-2	Stable

_____________________

(1) In March 2017, Moody's downgraded our senior secured rating to A2, from A1, and our unsecured credit rating to Baa1, from A3, while maintaining a negative outlook. Moody's cited weak financial metrics and a heightened degree of regulatory uncertainty 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,
	2017			2016
Operating Activities
Net income	$	78.4		$	75.4
Non-cash adjustments to net income	92.8			88.3
Changes in working capital	9.6			(26.8		)
Other noncurrent assets and liabilities	(3.0		)	4.1
Cash Provided by Operating Activities	177.8			141.0

Investing Activities
Property, plant and equipment additions	(119.1		)	(121.2		)
Other	0.4			0.1
Cash Used in Investing Activities	(118.7		)	(121.1		)

Financing Activities
Issuances of long-term debt, net	—			5.0
Issuances of short-term borrowings, net	2.8			26.9
Dividends on common stock	(50.4		)	(47.9		)
Financing costs	(0.1		)	(5.3		)
Other	0.4			(1.6		)
Cash Used in Financing Activities	(47.3		)	(22.9		)

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

Cash Provided by Operating Activities

As of June 30, 2017, cash and cash equivalents were $16.9 million as compared with $5.1 million at December 31, 2016 and $9.0 million at June 30, 2016. Cash provided by operating activities totaled $177.8 million for the six months ended June 30, 2017 as compared with $141.0 million during the six months ended June 30, 2016. This increase in operating cash flows is primarily due to lower 2016 cash flows due to customer refunds associated with the DGGS FERC ruling and interim rates in our South Dakota electric rate case of approximately $30.8 million and $7.2 million, respectively.

Cash Used in Investing Activities

Cash used in investing activities decreased by approximately $2.4 million as compared with the first six months of 2016. Plant additions during 2017 include 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 million.

Cash Used in Financing Activities

Cash used in financing activities totaled $47.3 million during the six months ended June 30, 2017 as compared with $22.9 million during the six months ended June 30, 2016. During the six months ended June 30, 2017, net cash used in financing activities reflects 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. See our Annual Report on Form 10-K for the year ended December 31, 2016 for additional discussion.



	Total		2017		2018		2019		2020		2021		Thereafter
	(in thousands)
Long-term debt	$	1,793,797	$	—	$	—	$	250,000	$	—	$	—	$	1,543,797
Capital leases	25,373		1,027		2,133		2,298		2,476		2,668		14,771
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
Qualifying facilities liability (2)	844,725		37,304		76,703		78,836		80,984		82,941		487,957
Supply and capacity contracts (3)	1,928,020		107,793		159,430		158,478		126,468		110,532		1,265,319
Contractual interest payments on debt (4)	1,330,494		40,771		81,541		73,616		65,691		65,393		1,003,482
Environmental remediation obligations (1)	5,900		700		1,650		2,150		800		600		N/A
Total Commitments (5)	$	6,297,552	$	503,209	$	335,141	$	578,955	$	289,693	$	275,228	$	4,315,326

_________________________


(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 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $844.7 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $654.5 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 our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 1.30% through maturity.


(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 of June 30, 2017, there have been no significant changes with regard to the critical accounting policies 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. The policies disclosed included the accounting for the following: goodwill and long-lived assets, QF liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.


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. The revolving credit facility bears interest at the lower of prime 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 revolving credit facility. Since commercial paper terms are short-term, we are subject to interest rate risk. As of June 30, 2017, we had approximately $303.7 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately $3.0 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, 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 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. 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 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.

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

•In 2016, the MPSC disallowed approximately $8.2 million of replacement power costs from a 2013 outage at Colstrip Unit 4, and approximately $1.3 million of costs related to generation portfolio modeling previously recovered through our electric tracker filings.

•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 on 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 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 costs associated with the risk of future carbon dioxide emissions regulations. In this same order, the MPSC indicated they will apply the 10-year contract term to us for future electric supply resource transactions. 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. This order may have a significant impact on our approach to meet our portfolio needs.

We must also comply with established reliability standards and requirements, 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.

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 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 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.

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 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, 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). We, along with a number of states and other parties, filed lawsuits against the EPA standards. In February 2016, the U.S. Supreme Court entered an order staying the implementation of the CPP standards. In a separate proceeding, in January 2017, the EPA denied our administrative Petition for Reconsideration that had requested the EPA reconsider the CPP on the grounds that the CO₂ 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 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. In light of the Executive Order, the future of the CPP regulations and associated guidance is uncertain. However, if the CPP survives the Executive Order, the legal challenges and is implemented as written, 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 and the uncertainties in the state approaches, the ultimate timing and impact of the CPP 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 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 the effect of increasing rates unless retail rates are designed to share the costs of the distribution grid across all customers that 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 use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation 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 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.

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.

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.

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. 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.

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.

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 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.

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 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 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. The annual minimum energy requirement is achievable under normal QF operations, 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 largest QF contracts due to variable contract terms. In estimating our 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	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

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