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 September 30, ~~2015~~2016

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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large Accelerated Filer x	Accelerated Filer o	Non-accelerated Filer o	Smaller Reporting Company 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

~~48,167,964~~48,327,642 shares outstanding at October ~~16, 2015~~14, 2016

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 Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	5
	Condensed Consolidated Balance Sheets — September 30, ~~2015~~2016 and December 31, ~~2014~~2015	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	7
	Condensed Consolidated Statements of Shareholders' Equity — Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2932
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4958
Item 4.	Controls and Procedures	5059
PART II. OTHER INFORMATION		5160
Item 1.	Legal Proceedings	5160
Item 1A.	Risk Factors	5160
Item 6.	Exhibits	5667
SIGNATURES		5769

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 ~~Report.~~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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Revenues
Electric	$	238,513		$	212,430		$	695,921		$	652,951		$	266,629		$	238,513		$	756,374		$	695,921
Gas	34,226			39,482			193,389			238,965			34,369			34,226			170,283			193,389
Total Revenues	272,739			251,912			889,310			891,916			300,998			272,739			926,657			889,310
Operating Expenses
Cost of sales	73,577			94,592			265,495			374,494			96,156			73,577			293,283			265,495
Operating, general and administrative	79,296			68,108			222,139			214,557			68,290			79,296			220,730			222,139
Property and other taxes	35,712			27,773			100,953			84,292			40,673			35,712			111,302			100,953
Depreciation and depletion	35,693			30,452			107,239			91,139			39,763			35,693			119,551			107,239
Total Operating Expenses	224,278			220,925			695,826			764,482			244,882			224,278			744,866			695,826
Operating Income	48,461			30,987			193,484			127,434			56,116			48,461			181,791			193,484
Interest Expense, net	(22,043		)	(18,794		)	(68,101		)	(57,887		)	(21,049		)	(22,043		)	(71,979		)	(68,101		)
Other Income (Expense)	3,769			(439		)	5,429			4,730
Other (Loss) Income													(121		)	3,769			4,176			5,429
Income Before Income Taxes	30,187			11,754			130,812			74,277			34,946			30,187			113,988			130,812
Income Tax (Expense) Benefit	(6,389		)	18,437			(24,616		)	9,240
Income Tax Benefit (Expense)													9,659			(6,389		)	4,240			(24,616		)
Net Income	$	23,798		$	30,191		$	106,196		$	83,517		$	44,605		$	23,798		$	118,228		$	106,196

Average Common Shares Outstanding	47,065			39,141			47,029			39,046			48,315			47,065			48,289			47,029
Basic Earnings per Average Common Share	$	0.51		$	0.77		$	2.26		$	2.14		$	0.92		$	0.51		$	2.45		$	2.26
Diluted Earnings per Average Common Share	$	0.51		$	0.77		$	2.25		$	2.13		$	0.92		$	0.51		$	2.44		$	2.25
Dividends Declared per Common Share	$	0.48		$	0.40		$	1.44		$	1.20		$	0.50		$	0.48		$	1.50		$	1.44

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in ~~thousands, except per share amounts)~~thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Net Income	$	23,798		$	30,191		$	106,196		$	83,517		$	44,605		$	23,798		$	118,228		$	106,196
Other comprehensive income (loss), net of tax:
Foreign currency translation	233			134			445			155			26			233			(84		)	445
Cash flow hedges:
Unrealized loss on cash flow hedging derivatives	—			(1,011		)	—			(1,011		)
Reclassification of net gains on derivative instruments	(555		)	(183		)	(735		)	(549		)	(1,506		)	(555		)	(1,432		)	(735		)
Total Other Comprehensive Loss	(322		)	(1,060		)	(290		)	(1,405		)	(1,480		)	(322		)	(1,516		)	(290		)
Comprehensive Income	$	23,476		$	29,131		$	105,906		$	82,112		$	43,125		$	23,476		$	116,712		$	105,906

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)


	September 30, 2015			December 31, 2014
							September 30, 2016			December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	10,135		$	20,362		$	5,063		$	11,980
Restricted cash	18,639			29,662			6,706			6,634
Accounts receivable, net	117,454			163,479			116,821			154,410
Inventories	58,692			55,094			54,311			53,458
Regulatory assets	38,389			47,374			44,501			51,348
Deferred income taxes	62,370			20,843
Other	10,157			14,071			10,937			8,830
Total current assets	315,836			350,885			238,339			286,660
Property, plant, and equipment, net	4,004,516			3,758,008			4,161,993			4,059,499
Goodwill	355,128			355,128			357,586			357,586
Regulatory assets	502,201			455,757			592,432			517,223
Other noncurrent assets	57,397			54,165			43,591			43,727
Total assets	$	5,235,078		$	4,973,943
Total Assets							$	5,393,941		$	5,264,695
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,803		$	1,730		$	1,942		$	1,837
Short-term borrowings	217,943			267,840			222,311			229,874
Accounts payable	60,235			81,961			57,217			74,511
Accrued expenses	226,024			206,882			241,185			183,988
Regulatory liabilities	68,908			56,169			24,159			80,990
Total current liabilities	574,913			614,582			546,814			571,200
Long-term capital leases	26,802			28,162			24,859			26,325
Long-term debt	1,782,123			1,662,099			1,794,519			1,768,183
Deferred income taxes	550,234			446,600			575,812			501,532
Noncurrent regulatory liabilities	374,460			362,228			392,857			378,711
Other noncurrent liabilities	407,700			382,489			410,273			418,570
Total liabilities	3,716,232			3,496,160
Commitments and Contingencies (Note 14)
Total Liabilities							3,745,134			3,664,521
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 50,687,962 and 47,067,963 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	507			505
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,936 and 48,327,642 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued							520			518
Treasury stock at cost	(94,031		)	(92,558		)	(95,852		)	(93,948		)
Paid-in capital	1,317,617			1,313,844			1,381,930			1,376,291
Retained earnings	303,809			264,758			372,321			325,909
Accumulated other comprehensive loss	(9,056		)	(8,766		)	(10,112		)	(8,596		)
Total shareholders' equity	1,518,846			1,477,783
Total liabilities and shareholders' equity	$	5,235,078		$	4,973,943
Total Shareholders' Equity							1,648,807			1,600,174
Total Liabilities and Shareholders' Equity							$	5,393,941		$	5,264,695

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2016			2015
OPERATING ACTIVITIES:
Net income	$	106,196		$	83,517		$	118,228		$	106,196
Items not affecting cash:
Depreciation and depletion	107,239			91,139			119,551			107,239
Amortization of debt issue costs, discount and deferred hedge gain	1,301			4,856			907			1,301
Stock-based compensation costs	3,275			2,238			4,474			3,275
Equity portion of allowance for funds used during construction	(6,568		)	(4,393		)	(3,053		)	(6,568		)
Gain on disposition of assets	(28		)	(347		)	(15		)	(28		)
Deferred income taxes	27,019			29,537			(4,720		)	27,019
Changes in current assets and liabilities:
Restricted cash	(735		)	(10,286		)	(72		)	(735		)
Accounts receivable	46,025			55,388			37,589			46,025
Inventories	(3,598		)	(7,357		)	(853		)	(3,598		)
Other current assets	4,006			5,086			(2,107		)	4,006
Accounts payable	(21,655		)	(30,298		)	(16,568		)	(21,655		)
Accrued expenses	19,307			26,257			60,852			19,307
Regulatory assets	8,985			(8,448		)	6,847			8,985
Regulatory liabilities	12,739			6,207			(56,831		)	12,739
Other noncurrent assets	(2,240		)	(34,650		)	(4,234		)	(2,240		)
Other noncurrent liabilities	3,209			(3,480		)	(2,007		)	3,209
Cash provided by operating activities	304,477			204,966
Cash Provided by Operating Activities							257,988			304,477
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(203,324		)	(186,085		)	(203,998		)	(203,324		)
Acquisitions	(143,328		)	1,367			—			(143,328		)
Proceeds from sale of assets	30,209			390			1,352			30,209
Change in restricted cash	11,758			(21,180		)	—			11,758
Investment in New Market Tax Credit program	—			(18,169		)
Cash used in investing activities	(304,685		)	(223,677		)
Cash Used in Investing Activities							(202,646		)	(304,685		)
FINANCING ACTIVITIES:
Treasury stock activity	(829		)	(881		)	(727		)	(829		)
Proceeds from issuance of common stock, net	—			13,320
Dividends on common stock	(67,145		)	(46,426		)	(71,816		)	(67,145		)
Issuance of long-term debt	270,000			25,789			249,660			270,000
Repayments on long-term debt	(150,024		)	(80		)	(225,205		)	(150,024		)
(Repayments) issuances of short-term borrowings, net	(49,897		)	28,995
Repayments of short-term borrowings, net							(7,563		)	(49,897		)
Financing costs	(12,124		)	(832		)	(6,608		)	(12,124		)
Cash (used in) provided by financing activities	(10,019		)	19,885
(Decrease) Increase in Cash and Cash Equivalents	(10,227		)	1,174
Cash Used in Financing Activities							(62,259		)	(10,019		)
Decrease in Cash and Cash Equivalents							(6,917		)	(10,227		)
Cash and Cash Equivalents, beginning of period	20,362			16,557			11,980			20,362
Cash and Cash Equivalents, end of period	$	10,135		$	17,731		$	5,063		$	10,135
Supplemental Cash Flow Information:
Cash paid during the period for:
Cash (received) paid during the period for:
Income taxes	$	27		$	28		$	(2,922	)	$	27
Interest	52,106			44,170			56,118			52,106
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	8,932			7,989
Capital expenditures included in trade accounts payable							11,803			8,932

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMMON 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 Income			Total Shareholders' Equity
Balance at December 31, 2013	42,340	3,595	$	423	$	910,184	$	(91,744	)	$	209,091		$	2,716		$	1,030,670

Net income	—	—	—		—		—			83,517			—			83,517
Foreign currency translation adjustment	—	—	—		—		—			—			155			155
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	—	—	—		—		—			—			(549		)	(549		)
Unrealized loss on cash flow hedging derivatives, net of tax	—	—	—		—		—			—			(1,011		)	(1,011		)
Stock-based compensation	118	—	—		2,727		(922		)	—			—			1,805
Issuance of shares	296	15	5		13,479		41			—			—			13,525
Dividends on common stock ($1.20 per share)	—	—	—		—		—			(46,426		)	—			(46,426		)
Balance at September 30, 2014	42,754	3,610	$	428	$	926,390	$	(92,625	)	$	246,182		$	1,311		$	1,081,686
																			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, 2014	50,522	3,607	$	505	$	1,313,844	$	(92,558	)	$	264,758		$	(8,766	)	$	1,477,783		50,522	3,607	$	505	$	1,313,844		$	(92,558	)	$	264,758		$	(8,766	)	$	1,477,783

Net income	—	—	—		—		—			106,196			—			106,196			—	—	—		—			—			106,196			—			106,196
Foreign currency translation adjustment	—	—	—		—		—			—			445			445			—	—	—		—			—			—			445			445
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	—	—	—		—		—			—			(735		)	(735		)
Reclassification of net gains on derivative instruments from Other Comprehensive Income (OCI) to net income, net of tax																			—	—	—		—			—			—			(735		)	(735		)
Stock-based compensation	166	—	—		3,304		(1,926		)	—			—			1,378			166	—	—		3,304			(1,926		)	—			—			1,378
Issuance of shares	—	13	2		469		453			—			—			924			—	13	2		469			453			—			—			924
Dividends on common stock ($1.44 per share)	—	—	—		—		—			(67,145		)	—			(67,145		)	—	—	—		—			—			(67,145		)	—			(67,145		)
Balance at September 30, 2015	50,688	3,620	$	507	$	1,317,617	$	(94,031	)	$	303,809		$	(9,056	)	$	1,518,846		50,688	3,620	$	507	$	1,317,617		$	(94,031	)	$	303,809		$	(9,056	)	$	1,518,846

Balance at December 31, 2015																			51,789	3,617	$	518	$	1,376,291		$	(93,948	)	$	325,909		$	(8,596	)	$	1,600,174

Net income																			—	—	—		—			—			118,228			—			118,228
Foreign currency translation adjustment																			—	—	—		—			—			—			(84		)	(84		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax																			—	—	—		—			—			—			(1,432		)	(1,432		)
Stock-based compensation																			168	13	—		5,650			(1,904		)	—			—			3,746
Issuance of shares																			—	—	2		(11		)				—			—			(9		)
Dividends on common stock ($1.50 per share)																			—	—	—		—			—			(71,816		)	—			(71,816		)
Balance at September 30, 2016																			51,957	3,630	$	520	$	1,381,930		$	(95,852	)	$	372,321		$	(10,112	)	$	1,648,807

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 ~~692,600~~701,000 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 September 30, ~~2015~~2016, 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 SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, ~~2014~~2015.

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 Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a 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 $~~279.5~~252.9 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In ~~April 2015,~~May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance that changes the presentation of debt issuance costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. The new guidance will be effective for us in our first quarter of 2016. Early adoption is permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

~~In May 2014, the 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. The FASB delayed the effective date of this guidance to the first quarter of 2018, with early adoption permitted as of the original effective date of the first quarter of 2017. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

In ~~January 2015,~~February 2016, the FASB issued revised guidance ~~which eliminates from GAAP~~on accounting for leases. The new standard requires a lessee to recognize in the ~~concept~~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 ~~an extraordinary item. As~~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 result, an entity will no longer (1) segregate an extraordinary item from the results of ordinary operations; (2) separately present an extraordinary item on its income statement, net of tax, after income from continuing operations; and (3) disclose income taxes and earnings-per-share data applicable to an extraordinary item.finance or operating lease. The new guidance will be effective for us in our first quarter of ~~2016~~2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating 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, and based on our initial analysis do not expect it to have a significant impact on our Financial Statements and disclosures.

In March 2016, the FASB issued guidance revising certain elements of the accounting for share-based payments. The new standard is intended to simplify several aspects of the accounting for share-based payment award transactions including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The new guidance will be effective for us in our first quarter of 2017, with early adoption permitted. We are currently evaluating the impact of adoption of this ~~standard to have a material effect~~guidance on our ~~reporting~~Financial Statements and ~~disclosure.~~disclosures.

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.

Accounting Standards Adopted

~~There have been no new accounting pronouncements~~In February 2015, the FASB issued consolidation guidance that eliminated two consolidation models and requires all legal

entities to be evaluated under a voting interest entity model or ~~changes~~a variable interest entity model. Both models require the reporting entity to identify whether it has a controlling financial interest in ~~accounting pronouncements~~a legal entity and is therefore required to consolidate the entity. We adopted this guidance during the ~~nine months ended September 30, 2015 that are~~first quarter of ~~significance, or potential significance,~~2016 with no material impact to ~~us.~~

~~(3) Acquisitions~~

~~Hydro Transaction~~our Financial Statements and disclosures.

In ~~November 2014, we completed~~April 2015, the ~~purchase~~FASB issued accounting guidance that changes the presentation of ~~11 hydroelectric generating facilities and associated~~debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, ~~located in Montana for an adjusted purchase price of approximately $904 million (Hydro Transaction). The addition of hydroelectric generation provides long-term supply diversity~~but adjustments to ~~our portfolio and reduces risks associated with variable fuel prices. We expect~~ the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control thecarrying cost of ~~supplying electricity to our customers. We expect to finalize~~debt. During the ~~purchase price allocation, including analysis of environmental matters and potential removal obligations, during the fourth~~first quarter of ~~2015.~~2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million and $13.0 million in the Condensed Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

(3) Regulatory Matters

~~Kerr Project -~~ ~~The Hydro Transaction included the Kerr Project. Upon the close of the Hydro Transaction, we assumed temporary ownership of the Kerr Project until it was conveyed to the Confederated Salish~~Montana Natural Gas Delivery and Kootenai Tribes of the Flathead Reservation (CSKT) on September 5, 2015, in accordance with the associated FERC license. Our purchase agreement for the Hydro Transaction included a $30 million reference price for the Kerr Project. In September 2015, the CSKT paid us $18.3 million, which was established through previous arbitration, and Talen Energy (formerly PPL Montana) paid the difference of $11.7 million to us. Upon receipt of the CSKT payment we conveyed the Kerr Project to the CSKT.Production Rate Filing

~~The~~In September 2016, we filed a natural gas rate case with the Montana Public Service Commission (MPSC) order approving the Hydro Transaction provided that customers would have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT. We sold any excess system generation during our temporary ownership of the Kerr Project in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. We believe the benefits of our temporary ownership of the Kerr Project exceeded any costs to customers.

We expect to make the required compliance filing during the fourth quarter of 2015 that will remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts for the Hydro Transaction with revised rates effective January 1, 2016.

~~South Dakota Wind Generation~~

In September 2015, we completed the purchase of the 80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments). The Beethoven project was not submitted in the South Dakota electric rate filing made in December 2014; however, we reached a stipulated settlement agreement in September 2015 that will allow us to include Beethoven in rate base and collect approximately $9.0 million annually. For further discussion of this settlement agreement see Note 4 - Regulatory Matters.

~~The purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition as follows:~~

Purchase Price Allocation (in millions)
Assets Acquired
Property Plant and Equipment $ 143.0
Other Prepayments 0.1
Total Assets Acquired $ 143.1

Liabilities Assumed
Other Current Liabilities $ 0.3
Total Liabilities Assumed $ 0.3
Total Purchase Price $ 142.8

We expect to finalize the purchase price allocation during the fourth quarter of 2015. The pro forma results as if the Beethoven acquisition occurred on January 1, 2015 would not be materially different from our financial results for the nine months ended September 30, 2015.

~~(4) Regulatory Matters~~

~~South Dakota Electric Rate Filing~~

~~In December 2014, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for~~requesting an annual increase to ~~electric~~natural gas rates ~~totaling~~of approximately ~~$26.5 million.~~$10.9 million, which includes approximately $7.4 million for delivery service and approximately $3.5 million for natural gas production. Our request was based on ~~an overall rate~~a return on equity of ~~return of 7.67% and~~10.35%, rate base of ~~$447.4 million.~~$432.1 million, and a capital structure of 53% debt and 47% equity. This filing includes a request for cost-recovery of two natural gas production fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin, which are recovered in customer rates on an interim basis, and a request that these fields be placed in permanent rates based on the actual cost of production.

~~In September 2015,~~Finally, we ~~reached a settlement with~~requested that approximately $5.6 million of the ~~SDPUC Staff and intervenors providing~~rate increase for ~~an increase in base rates of approximately $20.2 million, based~~delivery service be approved on an ~~overall rate~~interim basis to allow recovery of ~~return of 7.24%. In addition, the settlement would allow us to collect approximately $9 million annually related~~costs prior to the ~~Beethoven wind project as discussed above. The settlement is subject to approval~~conclusion of the ~~SDPUC, and~~full rate case. We expect to receive a ~~hearing is scheduled for October 2015. The SDPUC is expected to make a final determination in the case~~decision on our interim request by the end of ~~2015.~~

~~We have been collecting interim rates since July 1, 2015, based~~the first quarter of 2017. The MPSC has nine months in which to issue a final decision on our ~~original~~ filing. ~~We are recognizing revenue consistent with the settlement and we will refund any amounts overcollected by March 31, 2016.~~

Montana Electric and Natural Gas Tracker Filings

Each year we submit an electric and natural gas 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. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our ~~electric~~ supply procurement activities were prudent.

During the second quarter of ~~2015,~~2016, we filed our 2016 annual electric and natural gas ~~supply~~ tracker filings for the ~~2014/2015~~2015/2016 tracker ~~period and received~~period. The MPSC issued orders ~~from~~in July 2016 approving the ~~MPSC approving those~~ filings on an interim basis. ~~Our electric and natural gas supply tracker filings for the 2013/2014 and 2012/2013 tracker periods are part of consolidated dockets.~~

Electric ~~Tracker~~Trackers - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - ~~Our 2013/2014 electric tracker filing included market purchases made between July 2013~~The MPSC held a work session in March 2016 and ~~January 2014 for~~directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power ~~during an~~costs from a 2013 outage at Colstrip Unit ~~4. Inclusion of these~~4 and portfolio modeling costs in each of the ~~tracker filing is consistent with~~periods. On the ~~treatment of replacement power during previous outages. During~~same day, in a ~~June 2014 MPSC~~separate work session, ~~approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by~~ the MPSC ~~for additional prudency review. The Montana Consumer Counsel, Montana Environmental Information Center and Sierra Club have intervened in the consolidated docket~~directed staff to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A hearing was held in October 2015 related to the 2013/2014 and 2012/2013 consolidated tracker docket and we expect the MPSC to issue a final order by the first quarter of 2016.

~~Natural Gas Tracker~~ ~~- In October 2015, we received~~draft a final order in the ~~natural gas consolidated 2013/2014~~2015 Tracker that approved a stipulation between us and ~~2012/2013 tracker docket. This consolidated docket~~the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work sessions, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million, which included ~~our request to continue collecting~~$8.2 million of replacement power costs and $2.1 million of modeling costs.

In April 2016, we received the ~~cost of service for natural gas production interests acquired~~final written order in ~~December 2013 and in August 2012 in northern Montana's Bear Paw Basin (Bear Paw) on an interim basis. The MPSC final order requires that we revise~~ the ~~bridge rates currently used to reflect our actual fixed cost~~

requirements since acquisition of these interests. In addition, the order requires us to make a filing within the next 12 months to address the cost-recovery of our gas production fields. As of September 30, 2015 ~~we have deferred revenue of approximately $1.6 million~~Tracker, which was consistent with the work session. In May 2016, we received the final ~~order.~~written order in the Consolidated Docket. The written order upheld the March 2016 decision regarding replacement power costs and clarified the disallowance of modeling costs, resulting in a reduction of the disallowance of $0.8 million, which was reflected as a reduction in cost of sales in the second quarter of 2016. Based on the final orders, the impact of the disallowance totals $12.4 million, which includes interest of $2.9 million and is recorded in the Condensed Consolidated Statement of Income for the nine months ended September 30, 2016.

In June 2016, we filed an appeal of the 2015 Tracker decision regarding the disallowance of portfolio modeling costs in Montana District Court (Lewis & Clark County). Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket regarding the disallowance of Colstrip Unit 4 replacement power costs 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). While the courts are not obligated to rule on these appeals within a certain period of time, based on our experience, we believe we are likely to receive orders from the courts in these matters within 9-20 months of filing.

Electric and Natural Gas Lost Revenue Adjustment Mechanism - ~~Demand-side management (DSM) lowers~~In 2005, the MPSC approved an 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 kilowatt hour sales lost due to ~~customers. Base rates, including impacts of past DSM activities, are reset in general rate filings. Between rate filings,~~ the implementation of energy saving measures result in increased lost revenues related to DSM activities. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM through our supply tracker filings.

measures. In an order issued in October 2013 ~~which was~~ related to our 2011/2012 electric supply tracker, the MPSC required us to lower ~~our LRAM~~the calculated lost revenue recovery and imposed a new burden of proof on us for future ~~LRAM~~ recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In ~~June 2015, the MPSC held a hearing to address these issues. In~~ October 2015, the MPSC issued an order to eliminate the ~~LRAM~~lost revenue adjustment mechanism prospectively effective December 1, 2015.

Based on the October 2013 MPSC order, for the period July 1, 2012 through November 30, 2015, we ~~have~~ recognized $7.1 million of ~~DSM~~ lost revenues for each annual electric supply tracker period ~~(cumulatively July 1, 2012 through September 30, 2015)~~ and deferred the remaining ~~portion.~~$14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings. As discussed above, during the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of lost revenues included in each tracker period. As a result, we recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the Condensed Consolidated Statement of Income in the second quarter of 2016.

Hydro Compliance Filing

In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016. The adjustment to rates is being refunded to customers over 12 months, and as of September 30, 2015 we have cumulative deferred revenue of approximately $11.8 million, which is recorded within current regulatory liabilities in the Consolidated Balance Sheet. Since the 2012/2013 and 2013/2014 annual electric tracker filings are still subject to final approval, the MPSC may ultimately require us to refund more than2016, we have deferred ~~or approve recovery~~revenue remaining of ~~more DSM lost revenues than~~approximately $2.6 million that we ~~have recognized since July 2012.~~expect to refund to customers by the end of 2016.

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

In ~~April 2014, the FERC issued~~May 2016, we received an order ~~affirming~~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 ~~in September 2012,~~ regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded ~~we should allocate~~that only a ~~fraction~~portion of ~~the~~these costs ~~we believe, based on facts and the law,~~ should be allocated to FERC jurisdictional customers. We ~~have been recognizing~~ had deferred cumulative

revenue of approximately $27.3 million, consistent with the ALJ's initial ~~decision. As of September 30, 2015, we have cumulative deferred revenue of approximately $27.3 million,~~decision, which ~~is subject~~was refunded to ~~refund~~wholesale and ~~recorded within current regulatory liabilities~~choice customers in June 2016 in accordance with the ~~Consolidated Balance Sheets.~~FERC order.

In ~~May 2014,~~June 2016, we filed a ~~request~~petition for ~~rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if~~review of the cost allocation method is modified prospectively. There is no deadline by which FERC must act on our rehearing petition, but it could occur during 2015. Customer refunds, if any, will not be due until 30 days after a FERCFERC's May 2016 order ~~on rehearing. If unsuccessful on rehearing, we may appeal to a~~with the United States Circuit Court of ~~Appeals. The time line~~Appeals for ~~any such appeal would likely extend into 2016 or beyond.~~the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. WeAs of September 30, 2016, the DGGS net property, plant and equipment is approximately $160 million. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are ~~evaluating~~able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation ~~resources,~~resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including ~~our newly acquired hydro facilities, to facilitate~~regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. ~~Any~~The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

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

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


	Three Months Ended September 30,										Three Months Ended September 30,
	2015					2014					2016					2015
Income Before Income Taxes	$	30,187				$	11,754				$	34,946				$	30,187

Income tax calculated at 35% federal statutory rate	10,565			35.0	%	4,114			35.0	%	12,231			35.0	%	10,565			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(857		)	(2.8	)	(108		)	(0.9	)	(615		)	(1.8	)	(857		)	(2.8	)
Release of unrecognized tax benefit	—			—		(12,607		)	(107.3	)
Flow-through repairs deductions	(2,779		)	(9.2	)	(3,413		)	(29.0	)	(18,995		)	(54.4	)	(2,779		)	(9.2	)
Production tax credits	(733		)	(2.4	)	(300		)	(2.6	)	(2,218		)	(6.3	)	(733		)	(2.4	)
Plant and depreciation of flow through items	(374		)	(1.2	)	(685		)	(5.8	)	(243		)	(0.7	)	(374		)	(1.2	)
Prior year permanent return to accrual adjustments	1,025			3.4		(5,172		)	(44.0	)	—			—		1,025			3.4
Other, net	(458		)	(1.6	)	(266		)	(2.3	)	181			0.6		(458		)	(1.6	)
	(4,176		)	(13.8	)	(22,551		)	(191.9	)	(21,890		)	(62.6	)	(4,176		)	(13.8	)

Income tax expense (benefit)	$	6,389		21.2	%	$	(18,437	)	(156.9	)%
											$	(9,659	)	(27.6	)%	$	6,389		21.2	%


	Nine Months Ended September 30,										Nine Months Ended September 30,
	2015					2014					2016					2015
Income Before Income Taxes	$	130,812				$	74,277				$	113,988				$	130,812

Income tax calculated at 35% federal statutory rate	45,784			35.0	%	25,997			35.0	%	39,896			35.0	%	45,784			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(329		)	(0.3	)	257			0.3		(2,740		)	(2.4	)	(329		)	(0.3	)
Flow-through repairs deductions	(17,240		)	(13.2	)	(14,885		)	(20.0	)	(32,640		)	(28.6	)	(17,240		)	(13.2	)
Release of unrecognized tax benefit	—			—		(12,607		)	(17.0	)
Production tax credits	(2,645		)	(2.0	)	(2,054		)	(2.8	)	(7,317		)	(6.4	)	(2,645		)	(2.0	)
Plant and depreciation of flow through items	(1,000		)	(0.8	)	(182		)	(0.2	)	(1,427		)	(1.3	)	(1,000		)	(0.8	)
Prior year permanent return to accrual adjustments	1,025			0.8		(5,172		)	(7.0	)	(128		)	(0.1	)	1,025			0.8
Other, net	(979		)	(0.7	)	(594		)	(0.7	)	116			0.1		(979		)	(0.7	)
	(21,168		)	(16.2	)	(35,237		)	(47.4	)	(44,136		)	(38.7	)	(21,168		)	(16.2	)

Income tax expense (benefit)	$	24,616		18.8	%	$	(9,240	)	(12.4	)%
											$	(4,240	)	(3.7	)%	$	24,616		18.8	%

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.

In 2009, we received approval from the Internal Revenue Service (IRS) to change our tax accounting method related to the repair and maintenance of transmission and distribution utility assets and have recorded a current tax deduction in our Financial Statements for each period since. In 2013, the IRS issued guidance related to the repair and maintenance of utility generation assets. During the third quarter of 2016, we filed a tax accounting method change with the IRS consistent with the guidance for generation property. This enabled us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. As discussed above, we flow this current tax deduction through to our customers in rate cases. Consistent with this regulatory treatment, we recorded an income tax benefit of approximately $15.5 million during the three months ended September 30, 2016, of which approximately $12.5 million related to 2015 and prior tax years and is reflected in the flow-through repairs deductions line above.

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 ~~$96.4~~$90.0 million as of September 30, ~~2015~~2016, including approximately $~~65.3~~66.6 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 nine months ended September 30, ~~2015,~~2016 we ~~did not recognize~~recognized $0.5 million of expense for interest and penalties in the Condensed Consolidated Statements of ~~Income~~Income. As of September 30, 2016, we had $0.5 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2015, we did not recognize any expense for interest or penalties, and did not have any amounts accrued at ~~September 30, 2015~~ ~~and~~as of December 31, ~~2014, respectively,~~2015, for the payment of interest and penalties.

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

~~(6)~~(5) Goodwill

We completed our annual goodwill impairment test as of April 1, ~~2015,~~2016, 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 nine months ended September 30, ~~2015.~~2016. Goodwill by segment is as follows for both September 30, ~~2015~~2016 and December 31, ~~2014~~2015 (in thousands):


Electric	$	241,100	$	243,558
Natural gas	114,028		114,028
	$	355,128
Total			$	357,586

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

The following tables display the components of Other Comprehensive ~~Income (Loss)~~Loss (in thousands):


	Three Months Ended																Three Months Ended
	September 30, 2015								September 30, 2014								September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	233		$	—	$	233		$	134		$	—	$	134		$	26		$	—	$	26		$	233		$	—	$	233
Reclassification of net gains on derivative instruments	(901		)	346		(555		)	(297		)	114		(183		)	(2,448		)	942		(1,506		)	(901		)	346		(555		)
Unrealized loss on cash flow hedging derivatives	—			—		—			(1,644		)	633		(1,011		)
Other comprehensive (loss) income	$	(668	)	$	346	$	(322	)	$	(1,807	)	$	747	$	(1,060	)
Other comprehensive loss																	$	(2,422	)	$	942	$	(1,480	)	$	(668	)	$	346	$	(322	)


	Nine Months Ended																Nine Months Ended
	September 30, 2015								September 30, 2014								September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	445		$	—	$	445		$	155		$	—	$	155		$	(84	)	$	—	$	(84	)	$	445		$	—	$	445
Reclassification of net gains on derivative instruments	(1,187		)	452		(735		)	(891		)	342		(549		)	(2,324		)	892		(1,432		)	(1,187		)	452		(735		)
Unrealized loss on cash flow hedging derivatives	—			—		—			(1,644		)	633		(1,011		)
Other comprehensive (loss) income	$	(742	)	$	452	$	(290	)	$	(2,380	)	$	975	$	(1,405	)
Other comprehensive loss																	$	(2,408	)	$	892	$	(1,516	)	$	(742	)	$	452	$	(290	)

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


	September 30, 2015			December 31, 2014			September 30, 2016			December 31, 2015
Foreign currency translation	$	1,242		$	797		$	1,271		$	1,355
Derivative instruments designated as cash flow hedges	(9,051		)	(8,316		)	(10,446		)	(9,014		)
Pension and postretirement medical plans	(1,247		)	(1,247		)	(937		)	(937		)
Accumulated other comprehensive loss	$	(9,056	)	$	(8,766	)	$	(10,112	)	$	(8,596	)

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

September 30, 2015
Three Months Ended
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 $ (8,496 ) $ (1,247 ) $ 1,009
$ (8,734 )
Other comprehensive income before reclassifications —
—
233
233
Amounts reclassified from AOCI Interest Expense (555 ) —
—
(555 )
Net current-period other comprehensive (loss) income (555 ) —
233
(322 )
Ending balance $ (9,051 ) $ (1,247 ) $ 1,242
$ (9,056 )


		September 30, 2014												Three Months Ended
		Three Months Ended												September 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			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		$	3,147		$	(1,329	)	$	553	$	2,371			$	(8,940	)	$	(937	)	$	1,245	(8,632		)
Other comprehensive income before reclassifications		(1,011		)	—			134		(877		)		—			—			26		26
Amounts reclassified from AOCI	Interest Expense	(183		)	—			—		(183		)
Amounts reclassified from AOCL													Interest Expense	(1,506		)	—			—		(1,506		)
Net current-period other comprehensive (loss) income		(1,194		)	—			134		(1,060		)		(1,506		)	—			26		(1,480		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311			$	(10,446	)	$	(937	)	$	1,271	$	(10,112	)


		September 30, 2015												Three Months Ended
		Nine Months Ended												September 30, 2015
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total			Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,316	)	$	(1,247	)	$	797	$	(8,766	)		$	(8,496	)	$	(1,247	)	$	1,009	(8,734		)
Other comprehensive income before reclassifications		—			—			445		445
Amounts reclassified from AOCI	Interest Expense	(735		)	—			—		(735		)
Other comprehensive loss before reclassifications														—			—			233		233
Amounts reclassified from Accumulated Other Comprehensive Income (AOCI)													Interest Expense	(555		)	—			—		(555		)
Net current-period other comprehensive (loss) income		(735		)	—			445		(290		)		(555		)	—			233		(322		)
Ending balance		$	(9,051	)	$	(1,247	)	$	1,242	$	(9,056	)		$	(9,051	)	$	(1,247	)	$	1,242	$	(9,056	)

September 30, 2014
Nine Months Ended
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 $ 3,513
$ (1,329 ) $ 532
$ 2,716
Other comprehensive income before reclassifications (1,011 ) —
155
(856 )
Amounts reclassified from AOCI Interest Expense (549 ) —
—
(549 )
Net current-period other comprehensive (loss) income (1,560 ) —
155
(1,405 )
Ending balance $ 1,953
$ (1,329 ) $ 687
$ 1,311



		Nine Months Ended
		September 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		—			—			(84		)	(84		)
Amounts reclassified from AOCL	Interest Expense	(1,432		)	—			—			(1,432		)
Net current-period other comprehensive loss		(1,432		)	—			(84		)	(1,516		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271		$	(10,112	)



		Nine Months Ended
		September 30, 2015
	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		$	(8,316	)	$	(1,247	)	$	797	(8,766		)
Other comprehensive income before reclassifications		—			—			445		445
Amounts reclassified from AOCI	Interest Expense	(735		)	—			—		(735		)
Net current-period other comprehensive (loss) income		(735		)	—			445		(290		)
Ending balance		$	(9,051	)	$	(1,247	)	$	1,242	$	(9,056	)

~~(8)~~(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 within the Montana market.~~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. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. 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 September 30, ~~2015~~2016 and December 31, ~~2014~~2015. 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 ~~AOCI.~~AOCL. We reclassify these gains from ~~AOCI~~AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

Location of amount reclassified from AOCI to Income Amount Reclassified from AOCI into Income during the Nine Months Ended September 30, 2015

Interest rate contracts Interest Expense $ 1,187

A ~~net~~ pre-tax loss of approximately ~~$15.0~~$17.2 million is remaining in ~~AOCI~~AOCL as of September 30, ~~2015~~2016, and we expect to reclassify approximately ~~$0.3~~$0.6 million of ~~net~~ pre-tax ~~gains~~losses from ~~AOCI~~AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

~~(9)~~(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 87 - 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		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)										(in thousands)
September 30, 2015
September 30, 2016
Restricted cash	$	13,892	$	—	$	—	$	—	$	13,892	$	6,350	$	—	$	—	$	—	$	6,350
Rabbi trust investments	23,760		—		—		—		23,760		25,057		—		—		—		25,057
Total	$	37,652	$	—	$	—	$	—	$	37,652	$	31,407	$	—	$	—	$	—	$	31,407

December 31, 2014
December 31, 2015
Restricted cash	$	13,140	$	—	$	—	$	—	$	13,140	$	6,240	$	—	$	—	$	—	$	6,240
Rabbi trust investments	21,594		—		—		—		21,594		24,245		—		—		—		24,245
Total	$	34,734	$	—	$	—	$	—	$	34,734	$	30,485	$	—	$	—	$	—	$	30,485

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):


	September 30, 2015				December 31, 2014				September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,782,123	$	1,862,952	$	1,662,099	$	1,817,642	$	1,794,519	$	1,950,837	$	1,768,183	$	1,844,974

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.

~~(10)~~(9) Financing Activities

~~We financed the Beethoven wind project acquisition with a combination of $70~~In June 2016, we issued $60 million aggregate principal amount of South Dakota ~~first mortgage bonds, approximately $57 million of equity and the remainder with short-term borrowings. The $70 million of South Dakota first mortgage bonds were issued in September 2015~~First Mortgage Bonds at a fixed interest rate of ~~4.26%~~2.80% maturing in ~~2040. The~~2026. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018. In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended.

In August 2016, the City of Forsyth, Rosebud County, Montana issued $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds on our behalf. The bonds were issued at a fixed interest rate of 2.00% maturing in 2023. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and have been used to partially fund the redemption of the 4.65%, $170.2 million City of Forsyth Pollution Control Revenue Refunding Bonds due 2023 (Prior Bonds)

issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. ~~The equity transaction was completed in October 2015 through the issuance of 1,100,000 shares of our common stock at $51.81 per share.~~

the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.04%, $150 million of Montana First Mortgage Bonds due 2016 and finance incremental Montana capital expenditures.

~~(11)~~(10) 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
September 30, 2015	Electric			Gas			Other			Eliminations		Total
September 30, 2016															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	238,513		$	34,226		$	—		$	—	$	272,739		266,629			$	34,369		$	—		$	—	$	300,998
Cost of sales	66,197			7,380			—			—		73,577			89,681			6,475			—			—		96,156
Gross margin	172,316			26,846			—			—		199,162			176,948			27,894			—			—		204,842
Operating, general and administrative	58,298			19,843			1,155			—		79,296			50,460			19,141			(1,311		)	—		68,290
Property and other taxes	28,648			7,062			2			—		35,712			32,343			8,328			2			—		40,673
Depreciation and depletion	28,476			7,209			8			—		35,693			32,549			7,206			8			—		39,763
Operating income (loss)	56,894			(7,268		)	(1,165		)	—		48,461			61,596			(6,781		)	1,301			—		56,116
Interest expense	(19,078		)	(2,562		)	(403		)	—		(22,043		)	(19,099		)	(1,249		)	(701		)	—		(21,049		)
Other income	1,832			507			1,430			—		3,769
Income tax (expense) benefit	(6,553		)	1,883			(1,719		)	—		(6,389		)
Other income (loss)															982			345			(1,448		)	—		(121		)
Income tax benefit															7,946			1,169			544			—		9,659
Net income (loss)	$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798		$	51,425		$	(6,516	)	$	(304	)	$	—	$	44,605
Total assets	$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078		$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	57,813		$	14,341		$	—		$	—	$	72,154		$	66,322		$	16,430		$	—		—		$	82,752


Three Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
September 30, 2015															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912		$	238,513		$	34,226		$	—		$	—	$	272,739
Cost of sales	84,720			9,872			—			—		94,592			66,197			7,380			—			—		73,577
Gross margin	127,710			29,610			—			—		157,320			172,316			26,846			—			—		199,162
Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108			58,298			19,843			1,155			—		79,296
Property and other taxes	20,413			7,357			3			—		27,773			28,648			7,062			2			—		35,712
Depreciation and depletion	23,174			7,270			8			—		30,452			28,476			7,209			8			—		35,693
Operating income (loss)	35,595			(6,022		)	1,414			—		30,987			56,894			(7,268		)	(1,165		)	—		48,461
Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)	(19,078		)	(2,562		)	(403		)	—		(22,043		)
Other income (expense)	1,337			336			(2,112		)	—		(439		)
Income tax benefit	5,235			926			12,276			—		18,437
Other income															1,832			507			1,430			—		3,769
Income tax (expense) benefit															(6,553		)	1,883			(1,719		)	—		(6,389		)
Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191		$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298		$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078
Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065		$	57,813		$	14,341		$	—		$	—	$	72,154

Nine Months Ended
September 30, 2015 Electric Gas Other Eliminations Total
Operating revenues $ 695,921
$ 193,389
$ —
$ —
$ 889,310
Cost of sales 196,034
69,461
—
—
265,495
Gross margin 499,887
123,928
—
—
623,815
Operating, general and administrative 179,191
63,554
(20,606 ) —
222,139
Property and other taxes 78,987
21,958
8
—
100,953
Depreciation and depletion 85,523
21,691
25
—
107,239
Operating income 156,186
16,725
20,573
—
193,484
Interest expense (58,524 ) (8,304 ) (1,273 ) —
(68,101 )
Other income (expense) 4,773
1,349
(693 ) —
5,429
Income tax expense (16,364 ) (1,621 ) (6,631 ) —
(24,616 )
Net income $ 86,071
$ 8,149
$ 11,976
$ —
$ 106,196
Total assets $ 4,169,423
$ 1,057,919
$ 7,736
$ —
$ 5,235,078
Capital expenditures $ 171,800
$ 31,524
$ —
$ —
$ 203,324


Nine Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
September 30, 2016															Electric			Gas			Other			Eliminations		Total
Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916		$	756,374		$	170,283		$	—		$	—	$	926,657
Cost of sales	273,754			100,740			—			—		374,494			245,470			47,813			—			—		293,283
Gross margin	379,197			138,225			—			—		517,422			510,904			122,470			—			—		633,374
Operating, general and administrative	144,933			66,254			3,370			—		214,557			157,471			61,638			1,621			—		220,730
Property and other taxes	61,322			22,961			9			—		84,292			87,094			24,200			8			—		111,302
Depreciation and depletion	69,398			21,716			25			—		91,139			97,614			21,913			24			—		119,551
Operating income (loss)	103,544			27,294			(3,404		)	—		127,434			168,725			14,719			(1,653		)	—		181,791
Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)	(65,273		)	(5,018		)	(1,688		)	—		(71,979		)
Other income	3,204			876			650			—		4,730			2,136			925			1,115			—		4,176
Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
Income tax benefit (expense)															3,600			(574		)	1,214			—		4,240
Net income (loss)															$	109,188		$	10,052		$	(1,012	)	$	—	$	118,228
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298		$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085		$	165,885		$	38,113		$	—		—		$	203,998



Nine Months Ended
September 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	695,921		$	193,389		$	—		$	—	$	889,310
Cost of sales	196,034			69,461			—			—		265,495
Gross margin	499,887			123,928			—			—		623,815
Operating, general and administrative	179,191			63,554			(20,606		)	—		222,139
Property and other taxes	78,987			21,958			8			—		100,953
Depreciation and depletion	85,523			21,691			25			—		107,239
Operating income	156,186			16,725			20,573			—		193,484
Interest expense	(58,524		)	(8,304		)	(1,273		)	—		(68,101		)
Other income (expense)	4,773			1,349			(693		)	—		5,429
Income tax expense	(16,364		)	(1,621		)	(6,631		)	—		(24,616		)
Net income	$	86,071		$	8,149		$	11,976		$	—	$	106,196
Total assets	$	4,169,423		1,057,919			$	7,736		$	—	$	5,235,078
Capital expenditures	$	171,800		31,524			$	—		$	—	$	203,324

~~(12)~~(11) Earnings Per Share

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


	Three Months Ended		Three Months Ended
	September 30, 2015	September 30, 2014	September 30, 2016	September 30, 2015
Basic computation	47,065,082	39,141,148	48,314,783	47,065,082
Dilutive effect of
Dilutive effect of:
Performance share awards (1)	245,463	139,655	154,537	245,463

Diluted computation	47,310,545	39,280,803	48,469,320	47,310,545


	Nine Months Ended		Nine Months Ended
	September 30, 2015	September 30, 2014	September 30, 2016	September 30, 2015
Basic computation	47,028,924	39,045,790	48,288,678	47,028,924
Dilutive effect of
Dilutive effect of:
Performance share awards (1)	245,460	141,560	154,889	245,460

Diluted computation	47,274,384	39,187,350	48,443,567	47,274,384

______________

(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.

~~(13)~~(12) 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 September 30,						Three Months Ended September 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,939		$	3,091		$	123		$	132
Interest cost	6,553			6,544			198			197
Expected return on plan assets	(7,062		)	(7,890		)	(261		)	(242		)
Amortization of prior service cost	62			62			(471		)	(471		)
Recognized actuarial loss	2,472			2,659			78			96
Net Periodic Benefit Cost (Income)	$	4,964		$	4,466		$	(333	)	$	(288	)


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,091		$	2,708		$	132		$	116		8,819			$	9,272		$	369		$	395
Interest cost	6,544			6,536			197			214			19,658			19,631			596			590
Expected return on plan assets	(7,890		)	(7,377		)	(242		)	(245		)	(21,186		)	(23,671		)	(782		)	(727		)
Amortization of prior service cost	62			62			(471		)	(500		)	185			185			(1,412		)	(1,412		)
Recognized actuarial loss	2,659			530			96			87			7,416			7,976			236			289
Net Periodic Benefit Cost (Income)	$	4,466		$	2,459		$	(288	)	$	(328	)	$	14,892		$	13,393		$	(993	)	$	(865	)

Pension Benefits Other Postretirement Benefits
Nine Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 2014
Components of Net Periodic Benefit Cost (Income)
Service cost $ 9,272
$ 8,123
$ 395
$ 349
Interest cost 19,631
19,610
590
644
Expected return on plan assets (23,671 ) (22,130 ) (727 ) (736 )
Amortization of prior service cost 185
185
(1,412 ) (1,499 )
Recognized actuarial loss 7,976
1,589
289
261
Net Periodic Benefit Cost (Income) $ 13,393
$ 7,377
$ (865 ) $ (981 )

~~(14)~~(13) 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 ~~$26.4~~$27 million to ~~$35.0~~$32 million. As of September 30, ~~2015,~~2016, we have a reserve of approximately ~~$28.3~~$30.3 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. During the second quarter of 2015, we reached a settlement agreement with an insurance carrier for the former Montana Power Company for what were primarily generation related environmental remediation costs. As a result of this settlement, we recognized a net recovery of approximately $20.8 million, which is reflected as a reduction to operating expenses in our other segment. The environmental remediation costs were never reflected in customer rates and the litigation expenses have not been treated as utility expenses. In a 2002 order approving NorthWestern’s acquisition of the transmission and distribution assets of the Montana Power Company, the MPSC approved a stipulation in which NorthWestern agreed to release its customers from all environmental liabilities associated with the Montana Power Company’s generation assets. While we believe the recovery we recognized as a reduction to operating expenses is not subject to refund to customers, the MPSC could disagree with us and could ultimately require us to refund all or a portion of the net recovery to customers.

Manufactured Gas Plants - Approximately ~~$23.4~~$23.7 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, ~~and~~ implementing remedial actions ~~at the Aberdeen site~~ pursuant to

work plans approved by the South Dakota Department of Environment and Natural Resources, ~~(DENR). Our current~~and conducting ongoing monitoring and operation and maintenance activities. As of September 30, 2016, the reserve for remediation costs at this site is approximately ~~$10.4~~$11.1 million, and we estimate that approximately ~~$7.5~~$6.5 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 letter of Notice of Potential Liability and Request for Remedial Action regarding the Helena site. An initial scoping meeting with MDEQ regarding this letter has not yet been scheduled. 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 and Helena sites.

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 ~~Missoula County Water Quality Board (MCWQB).~~MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. The ~~MCWQB deferred all decision making~~additional investigation work began in December 2015 and has continued in 2016. The result of the additional investigation work may lead to the ~~MDEQ, but suggested additional site delineation. A work plan is being prepared to address further delineation and proposed work is anticipated for the fourth quarter~~development of ~~2015.~~site-specific risk-based remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, ~~at these sites or~~ if any, ~~additional actions beyond monitored natural attenuation will be required.~~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.~~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 ~~coal fired and~~ 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.

On August 3, 2015, the EPA released for publication in the Federal Register, the final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed ~~stationary combustion turbines.~~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.

In a separate action that also affects power plants, on August 3, 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d)~~. EPA refers to this rule as the~~ (the Clean Power Plan, or ~~CPP.~~CPP). The CPP ~~specifically~~ establishes ~~CO2~~CO₂ emission performance standards for existing electric utility steam generating units and ~~stationary combustion turbines.~~NGCC units. States may develop implementation plans for affected units to meet the individual state targets established in the CPP or may adopt a federal plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour (MWH)) or mass-based tonnage limits for ~~CO2.~~CO₂. The 2030 rate-based requirement for all existing affected generating units in ~~Montana and~~ South Dakota and Montana is ~~1,305~~1,167 and ~~1,167~~1,305 pounds per MWH, respectively. The ~~mass-based~~rate-based approach ~~for existing affected generating units calls for~~requires a 3738.4 percent reduction in South Dakota and a 47.4 percent reduction in Montana from 2012 levels by ~~2030 in Montana.~~2030. The mass-based approach for existing units in South Dakota ~~permits an 11~~requires a 30.9 percent ~~increase~~decrease by 2030, while in Montana the mass-based approach requires a 41 percent decrease by 2030. States ~~are~~were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, ~~but may~~and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The initial performance period for compliance under the CPP would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program ~~which~~that would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program ~~which~~that would allow trading of allowances with an allowance equal to one short ton of ~~CO2;~~CO₂; and a state measures program that would allow intra-state trading to achieve the state-wide average emission rate.

On August 3, 2015, the EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an

emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one of the two options. ~~Comments~~

The CPP reduction of 47.4 percent in carbon dioxide emissions in Montana by 2030 is the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the ~~proposed~~EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility in southeast Montana as a scenario for complying with the federal ~~plan~~rule. The study's conclusions describe the likely loss of jobs and ~~model trading rule will be due ninety days after it~~population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Colstrip Unit 4 represents approximately 25 percent of our customer needs. Closing all four Colstrip units would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing all four Colstrip units would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to and lower electric customer bills.

On October 23, 2015, the same date the CPP was published in the Federal ~~Register.~~Register, we along with other utilities, trade groups, coal producers, and labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefing on the merits. On January 26, 2016, 29 states and state agencies asked the U.S. Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we were among the utilities seeking a stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the CPP. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, and on September 27, 2016, the Court held oral argument in the matter. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018.

On December 22, 2015 we also filed an administrative Petition for Reconsideration with the EPA, requesting that it reconsider the CPP, on the grounds that the CO₂ reductions in the CPP were substantially greater in Montana than in the proposed rule. We also requested EPA stay the CPP while it considered our Petition for Reconsideration. At this time, the EPA has taken no action on the Petition for Reconsideration or stay request.

On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the prevention of significant deterioration program, which includes most electric generating units.

Requirements to reduce GHG emissions ~~from stationary sources~~ could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Although there continues to be proposed legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as droughts, floods and tornadoes, in the locations where we operate or have interests.

We are evaluating the implications of these rules and technology available to achieve the ~~CO2~~CO₂ emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters ~~nor~~or what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission 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.

~~Coal Combustion Residuals (CCRs)~~ - In April 2015, the EPA published its final rule regulating CCRs, imposing extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plants and not closed. Under the rule, the EPA will regulate CCRs as non-hazardous under the Resource Conservation and Recovery Act Subtitle B and allow beneficial use of CCRs, with some restrictions. The CCR rule will become effective on October 14, 2015. The rule's requirements for covered CCR impoundments and landfills include commencement or completion of closure activities generally between three and ten years from certain triggering events. Based on our initial assessment of these requirements, during the second quarter of 2015 we recorded an increase to our existing asset retirement obligations (AROs) of approximately $12 million. AROs represent the anticipated costs of removing assets upon retirement and are provided for over the life of those assets as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. All costs of the rule are expected to be recovered from customers in future rates. Therefore, consistent with this regulated treatment, we reflect this increase to the accrual of removal costs by increasing our regulatory liability. Further, we do not have any assets that are legally restricted related to the settlement of CCR related asset retirement obligations.

The actual asset retirement costs related to the CCR Rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. We will coordinate with the plant operators and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, we will update the ARO obligation for these changes in estimates, which could be material.

Legislation has been introduced in Congress to permanently designate coal ash as non-hazardous and establish a national system to regulate coal ash disposal, but leave enforcement largely to states. We cannot predict at this time the final outcome of any such legislation and what impact, if any, it would have on us.

Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act ~~(CWA)~~ 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 Second Circuit Court of Appeals.

~~On September 30,~~In November 2015, the EPA ~~issued~~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; however, it~~regulations. Challenges to the final rule have been filed in the Fifth Circuit Court of Appeals, indicating 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.

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 such 'Class I' areas.

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 Court 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 U.S. Court of Appeals for the District of Columbia Circuit, and ~~on July 31 the litigation was formally sent back to~~ the D.C. Circuit ~~which will decide whether the standards will be vacated or will remain in place while the EPA addresses the Supreme Court decision. The EPA indicated that it will seek a remand~~remanded, without vacatur, of the MATS rule ~~and in support of that request,~~to the EPA, ~~will submit to~~leaving the ~~court a declaration establishing a plan to "complete~~rule in place. In April 2016, the ~~required consideration of costs" to support the~~EPA published its final supplemental finding that it is "appropriate and ~~necessary finding" by spring 2016. Installation~~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, installation or upgrading of relevant environmental controls at our affected plants is complete ~~or they have received compliance extensions, as applicable. At this time,~~and we ~~cannot predict whether~~are controlling emissions of mercury under the state and ~~when compliance with the~~Federal MATS ~~rule ultimately will be required.~~rules.

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide ~~(SO2)~~(SO₂) were to be required in certain states beginning in 2012. In April 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. In December, 2015 EPA published a proposed update to the CSAPR rule. Litigation of the remaining CSAPR lawsuits ~~continues, with a decision expected by the end of 2015.~~is pending.

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.

In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Units 3 and 4 do not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised ~~Plan~~plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana (now Talen Montana), 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 U.S. Court of Appeals for the Ninth Circuit. ~~Montana Environmental Information Center~~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 U.S. Court of Appeals for 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.

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.

~~South Dakota~~. Each state is required by the CPP to submit a satisfactory plan to EPA by September 2018. The ~~South Dakota DENR determined~~state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the ~~Big Stone plant,~~plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us. In addition, compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in ~~which we~~January 2016, did not have a ~~23.4% ownership, is subject to the BART requirements~~significant impact at any of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant must install and operate a new BART compliant air quality control system (AQCS) to reduce SOour jointly owned facilities.₂, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of the SIP. The estimated total project cost for the AQCS at the Big Stone plant is approximately $384 million (our share is 23.4%). As of ~~September 30, 2015~~, we have capitalized costs of approximately $95.1 million (including allowance for funds used during construction) related to this project, which is expected to be operational in the first quarter of 2016.

Based on the final MATS rule, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. The South Dakota DENR granted Big Stone an extension to comply with MATS, such that the new compliance deadline is April 16, 2016. New mercury emissions monitoring equipment will be required.

North ~~Dakota.~~Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx ~~emissions.~~emissions by July 2018. In 2016, Coyote ~~must install~~completed installation of control equipment to ~~limit its~~maintain compliance with the lower NOx emissions toof 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and ~~shutdown, beginning on July 1, 2018.~~shutdown. The ~~current estimate of the total~~ cost of the ~~project is approximately $9.0 million (our share is 10.0%).~~

~~Based on the final MATS rule, Coyote will meet the requirements by using activated carbon injection for mercury control. Initial compliance~~control equipment was ~~demonstrated during the third quarter of 2015.~~

~~Iowa~~. The Neal #4 generating facility, in which we have an 8.7% ownership, completed the installation of a scrubber, baghouse, activated carbon injection and a selective non-catalytic reduction system in 2013 to comply with national ambient air quality standards and the MATS.not significant.

Montana.Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's ~~CCR Rule.~~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~~$90.0 million (our share is ~~30.0%~~30%) over the remaining life of the facility. In addition, Unit 4 is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS and therefore in compliance with the Federal MATS.

See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation.

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

Colstrip Litigation

On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of the Colstrip Generating Station (Colstrip), including us, as well as Talen Montana (Talen), the operator or managing agent of the ~~station (Defendants).~~ station. Colstrip consists of four coal fired generating units. Colstrip Units 1 and 2 are older than Units 3 and 4. We do not have an ownership interest in Units 1 and 2. We have a 30 percent joint interest in Unit 4 and a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4.

On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory ~~Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint~~Relief that dropped claims associated with projects completed before 2001, ~~the~~ Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.

In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of ~~SO2,~~SO₂, NOx and particulate matter and (b) were “major modifications” subject to

permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits.

~~On May 3,~~In 2013, the Colstrip owners and operator filed a partial ~~motion~~motions to dismiss, seeking dismissal of 36 of the 39 claims asserted in the original complaint. The motion was not ruled upon, and the Colstrip owners filed a second motion to dismiss the Amended Complaint on October 11, 2013, incorporating parts of the first motion and supplementing it with new authorities and with regard to new claims contained in the Amended Complaint.

dismiss. On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications.

The parties filed a joint notice (Notice) on April 21, 2014, that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the United States Magistrate Judge (Magistrate) issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ ~~motion~~motions to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the ~~U.S. Federal District~~ Court, ~~Judge,~~ and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions.

On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which ~~alleges~~alleged a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014. ~~Since~~After filing the Second Amended Complaint, Plaintiffs ~~have~~ indicated that they ~~are~~were no longer pursuing a number of claims and projects thereby reducing their total ~~claims~~ to eight claims relating to four projects. The parties ~~have~~ filed motions for summary judgment and briefs in support with regard to issues affecting the remaining ~~claims, and~~claims.

On December 1, 2015, the ~~motions for summary judgment are fully briefed. Oral~~Court held oral argument on all pending motions for summary judgment, isand on December 31, 2015, the Magistrate issued findings and recommendations which (a) denied Plaintiffs’ motion for partial summary judgment regarding routine maintenance, repair and replacement; (b) denied Plaintiffs’ motion for partial summary judgment that the redesign projects for the Unit 1 and 4 turbines and the Unit 1 economizer were not “like kind replacements”; (c) granted Defendants’ motion for partial summary judgment regarding Plaintiffs’ use of the “actual-to-potential” emissions test; (d) granted in part and denied in part Plaintiffs’ motion for partial summary judgment regarding the allowable period from which to select a baseline for the Unit 3 reheater project; (e) granted in part and denied in part Defendants’ motion for partial summary judgment on baseline selection; and (f) granted Defendants’ motion for partial summary judgment on emissions calculations for alleged aggregated turbine and safety valve project.

With the matter scheduled ~~for December 1, 2015, and~~to go to a bench trial, ~~is scheduled for~~on April 26, 2016, the parties filed a joint motion to vacate the May 31, ~~2016.~~2016, trial date and to stay all deadlines, to allow the parties to settle the litigation. On July 12, 2016, the parties lodged a proposed consent decree with the Court. The Court entered the consent decree on September 6, 2016, dismissing all of the claims against all units, including Colstrip Unit 4, the only unit in which we have an ownership interest. While the consent decree does not provide a shut-down date for Units 3 and 4, it does provide that Units 1 and 2 must be shut down by July 1, 2022. Units 1 and 2 are owned solely by Talen and Puget Sound Energy. We had no role in the decisions regarding Units 1 and 2 as we have no ownership interest in those units. With the anticipated shutdown of Units 1 and 2, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. We do not anticipate that this increase will have a significant impact on our results of operations or cash flows. However, the ultimate shutdown of Talen's share of Colstrip Units 1 and 2 will have a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines.

~~We intend~~The consent decree gave the Plaintiffs and Defendants each the right to ~~vigorously defend this lawsuit. At this time,~~seek recovery of attorneys’ fees and costs from the other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. While we cannot predict an outcome ~~nor is it reasonably possible to estimate~~on the ~~amount~~opposing motions seeking attorneys’ fees and costs, we do not anticipate that the outcome will have a significant impact on our results of operations or ~~range of loss, if any, that would be associated with an adverse decision.~~cash flows.

Billings, Montana Refinery Outage Claim

In August 2014, we received a ~~demand~~ letter from athe ExxonMobil refinery in Billings claiming that it had sustained ~~damages of~~ 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 $65.6 million. We dispute ~~the claim~~ExxonMobil’s claims and intend to vigorously defend ~~against it.~~this lawsuit. We have reported the refinery's ~~claim~~claims and lawsuit to our liability insurance ~~carrier~~carriers under our ~~primary~~liability insurance ~~policy,~~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. This matter is in the initial stages and we cannot predict an outcome or estimate the amount or range of loss ~~if any,~~ that would be associated with an adverse result.

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), and 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. The parties have fully briefed the issue and we have requested oral argument. Talen’s and our motions to dismiss, the State’s motions for remand and our request for oral argument, remain pending before the Federal District Court.

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, on remand, the Federal District Court (or the State District Court if the case is remanded back 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 ~~692,600~~701,000 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, ~~2014~~.2015.

~~Significant~~As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2016 and 2015.



HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2015 RESULTS



	Quarter-over-Quarter Change

Gross Margin by Segment⁽¹⁾
Electric	$4.6M	é	2.7%
Natural Gas	$1.1M	é	4.1%


Operating Income	$7.6M	é	15.8%


Net Income	$20.8M	é	87.4%


EPS (Diluted)	$0.41	é	80.4%

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



SIGNIFICANT DEVELOPMENTS IN Q3 2016



	Ÿ	An increase in net income of $20.8 million, primarily due to a $15.3 million tax benefit as part of a tax accounting change related to costs to repair generation property along with improved gross margin driven by an increase in South Dakota electric rates.

	Ÿ	Filed a Montana natural gas delivery service and production case requesting an annual increase in base rates of approximately $10.9 million.

	Ÿ	Received proceeds from the City of Forsyth's issuance of $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds at a fixed interest rate of 2.00% maturing in 2023. Proceeds plus available funds were used to redeem the City of Forsyth's 4.65%, $170.2 million Pollution Control Revenue Bonds due 2023.

	Ÿ	Issuance of $45 million of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes.

Following is a brief overview of significant items for 2016, and a discussion of our strategy and outlook.



SIGNIFICANT TRENDS AND REGULATION

Montana Natural Gas Delivery and Production Rate Filing

In September 2016, we filed a natural gas rate case with the Montana Public Service Commission (MPSC) requesting an annual increase to natural gas rates of approximately $10.9 million, which includes approximately $7.4 million for delivery service and approximately $3.5 million for natural gas production. Our request was based on a return on equity of 10.35%, rate base of $432.1 million, and a capital structure of 53% debt and 47% equity. This filing includes a request for cost-recovery of two natural gas production fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin, which are recovered in customer rates on an interim basis, and a request that these fields be placed in permanent rates based on the actual cost of production.

Finally, we requested that approximately $5.6 million of the rate increase for delivery service be approved on an interim basis to allow recovery of costs prior to the conclusion of the full rate case. We expect to receive a decision on our interim request by the end of the first quarter of 2017. The MPSC has nine months in which to issue a final decision on our filing.

Generation Tax Repairs

In 2009, we received approval from the IRS to change our tax accounting method related to the repair and maintenance of transmission and distribution utility assets and have recorded a current tax deduction in our Financial Statements for each period since. In 2013, the IRS issued guidance related to the repair and maintenance of utility generation assets. During the third quarter of 2016, we filed a tax accounting method change with the IRS consistent with this IRS guidance for generation property. This allowed us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes, which is flowed through to our customers in rate cases. See Note 4 - Income Taxes in the Notes to Condensed Consolidated Financial Statements for further discussion.

Consistent with this regulatory treatment, we recorded an income tax benefit of approximately $15.5 million during the three months ended September 30, 2016, of which approximately $12.5 million related to 2015 ~~include:~~and prior tax years.

~~Completed~~

Montana Electric and Natural Gas Tracker Filings

Electric Tracker - The MPSC held a work session in March 2016 and directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs. On the ~~purchase~~same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs.

In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. In May 2016, we received the final written order in the Consolidated Docket. The written order clarified the disallowance of modeling costs, resulting in a reduction of the ~~80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments). We financed~~disallowance recorded during the ~~Beethoven wind project acquisition with a combination~~second quarter of $70 million of South Dakota first mortgage bonds, approximately $57 million of equity and the remainder with short-term borrowings. The $70 million of South Dakota first mortgage bonds were issued in September 2015 at a fixed interest rate of 4.26% maturing in 2040. The equity transaction was completed in October 2015 through the issuance of 1,100,000 shares of our common stock at $51.81 per share.

Reached a settlement in our South Dakota electric rate filing with the SDPUC Staff and intervenors providing for an increase in base rates of approximately $20.2 million, based on an overall rate of return of 7.24%. In addition, if approved by the SDPUC, the settlement will allow us to collect approximately $9.0 million annually related to the Beethoven wind project.

~~RESULTS OF OPERATIONS~~2016.

~~Net income~~Based on the final orders, the impact of the disallowance totals $12.4 million, which includes interest of $2.9 million and is recorded in the Condensed Consolidated Statement of Income for the ~~three~~nine months ended September 30, 2016.

Electric and Natural Gas Lost Revenue Adjustment Mechanism - In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was ~~$23.8 million, or $0.51 per diluted share,~~established in 2005 by the MPSC as ~~compared with net income~~a component of ~~$30.2 million, or $0.77 per diluted share,~~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 electric and natural supply tracker. Lost revenues were removed prospectively effective December 1, 2015.

Based on an October 2013 MPSC order, for the ~~same~~ period July 1, 2012 through November 30, 2015, we recognized $7.1 million of lost revenues for each annual electric supply tracker period and deferred the remaining $14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings. As discussed above, during the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of the lost revenues included in ~~2014. This decrease~~each tracker period.

We recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the second quarter of 2016 based on the final orders in our tracker filings.

Hydro Compliance Filing

The MPSC order approving our acquisition of the hydro assets provided that customers would have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes (CSKT). We sold any excess system generation, which was primarily due to ~~an income tax~~our temporary ownership of Kerr, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. Therefore, during our temporary ownership a net benefit of ~~$16.9~~approximately $2.7 million ~~included in~~was provided to customers and there was no benefit to shareholders. In December 2015, we submitted the required compliance filing to remove Kerr from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our ~~2014 results~~hydro generation rate based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the ~~release~~conveyance of ~~previously unrecognized tax benefits, partly offset~~Kerr. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016.

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

In May 2016, we received an order from the 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 deferred cumulative 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. A briefing schedule has been established, with final briefs due by the ~~favorable impacts~~end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our ~~Hydro Transaction.~~biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

Montana Electricity Supply Resource Procurement Plan

In March 2016, we submitted our electricity supply resource procurement plan (the Plan) to the MPSC, which is updated and filed every two years. The Plan is meant to provide a road map to our stakeholders, including our customers and regulators regarding how we expect to respond to future supply needs and is subject to review and public comment. While we have acquired a significant amount of generation capacity, a significant capacity resource deficit persists. The Plan identifies how to best meet the capacity need and includes a set of action plans we expect to implement on a going forward basis. In addition to meeting peak needs, national reliability standards effective in July 2016 require us to have even greater generation capacity available and be capable of increasing or decreasing output to address the intermittent nature of generation such as wind. To address the need for more generation capacity, the analysis indicates adding natural gas-fired generation is the lowest-cost/

least-risk approach for addressing customers’ peak demand needs. In addition, we are evaluating adding incremental generation to our hydro capability as a zero carbon alternative.

Supply Investments

We updated our capital spending forecast during the first quarter of 2016 to reflect the Montana procurement plan and our analysis of needs in South Dakota. This included incremental investment of approximately $122 million on internal combustion facilities in Montana, and approximately $65 million of peaking facilities in South Dakota over the five year period that was not included in the forecast in our most recent Form 10-K. Prior to any generation investment we will work with our regulators to define a clear regulatory recovery approach.



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 September 30, ~~2015~~2016 Compared with the Three Months Ended September 30, ~~2014~~2015


	Three Months Ended September 30,									Three Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change		% Change
	(dollars in millions)									(dollars in millions)
Operating Revenues
Electric	$	238.5	$	212.4	$	26.1		12.3	%	$	266.6	$	238.5	$	28.1	11.8	%
Natural Gas	34.2		39.5		(5.3		)	(13.4	)	34.4		34.2		0.2		0.6
	$	272.7	$	251.9	$	20.8		8.3	%
Total Operating Revenues										$	301.0	$	272.7	$	28.3	10.4	%


	Three Months Ended September 30,									Three Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Cost of Sales
Electric	$	66.2	$	84.7	$	(18.5	)	(21.8	)%	$	89.7	$	66.2	$	23.5		35.5	%
Natural Gas	7.4		9.9		(2.5		)	(25.3	)	6.5		7.4		(0.9		)	(12.2	)
	$	73.6	$	94.6	$	(21.0	)	(22.2	)%
Total Cost of Sales										$	96.2	$	73.6	$	22.6		30.7	%


	Three Months Ended September 30,									Three Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change		% Change
	(dollars in millions)									(dollars in millions)
Gross Margin
Electric	$	172.3	$	127.7	$	44.6		34.9	%	$	176.9	$	172.3	$	4.6	2.7	%
Natural Gas	26.8		29.6		(2.8		)	(9.5	)	27.9		26.8		1.1		4.1
	$	199.1	$	157.3	$	41.8		26.6	%
Total Gross Margin										$	204.8	$	199.1	$	5.7	2.9	%

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

Gross Margin 2015 vs. 2014
(in millions)
Hydro operations $ 40.4
South Dakota electric interim rate increase (subject to refund)
1.8
Property tax tracker 1.3
Electric retail volumes 1.1
Electric transmission capacity (0.9 )
Natural gas retail volumes (0.5 )
Gas production deferral (0.4 )
Other (1.0 )
Increase in Consolidated Gross Margin $ 41.8



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota electric rate increase	$	9.2
Natural gas retail volumes	1.4
Lost revenue adjustment mechanism	(1.8		)
Electric retail volumes	(0.4		)
Electric transmission	(0.4		)
Natural gas production	(0.2		)
Other	(0.3		)
Change in Gross Margin Impacting Net Income	7.5

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(4.3		)
Production tax credits flowed-through trackers	(2.1		)
Natural gas production gathering fees	(0.1		)
Property taxes recovered in trackers	4.7
Change in Items Offset Within Net Income	(1.8		)
Increase in Consolidated Gross Margin	$	5.7

Consolidated gross margin for items impacting net income increased ~~$41.8~~$7.5 million, ~~primarily~~ due to the following:

An increase in ~~generation margin from the November 2014 Hydro Transaction;~~

~~An increase in~~ South Dakota electric ~~rates implemented on an interim basis in July 2015;~~

~~An increase in property taxes included in trackers;~~rates; and

An increase in ~~electric~~natural gas retail volumes due primarily to ~~customer growth in the residential and commercial categories and warmer~~colder late summer weather in ~~South Dakota.~~our Montana jurisdiction and customer growth.

These increases were partly offset by:

The elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs;

A decrease in electric retail volumes due primarily to colder late summer weather in Montana, along with lower industrial volumes of a large Montana customer; partly offset by customer growth and warmer summer weather in South Dakota;

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

A decrease in natural gas ~~residential and commercial retail volumes;~~production margin due to lower overhead fees.

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

A decrease in revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);

A decrease in revenues for production tax credits primarily associated with the Beethoven wind generation project, which is a reduction in our customers rates (offset by reduced income tax expense);

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

~~A deferral of interim gas production revenue based on actual costs~~An increase in ~~accordance with the final order~~revenues for property taxes included in ~~the natural gas consolidated 2013/2014 and 2012/2013 tracker docket received in October 2015.~~trackers (offset by increased property tax expense).


	Three Months Ended September 30,								Three Months Ended September 30,
	2015		2014		Change		% Change		2016		2015		Change			% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	79.3	$	68.1	$	11.2	16.4	%	$	68.3	$	79.3	$	(11.0	)	(13.9	)%
Property and other taxes	35.7		27.8		7.9		28.4		40.7		35.7		5.0			14.0
Depreciation and depletion	35.7		30.5		5.2		17.0		39.8		35.7		4.1			11.5
	$	150.7	$	126.4	$	24.3	19.2	%	$	148.8	$	150.7	$	(1.9	)	(1.3	)%

Consolidated operating, general and administrative expenses were $68.3 million for the three months ended September 30, 2016, as compared with $79.3 million for the three months ended September 30, ~~2015, as compared with $68.1 million for the three months ended September 30, 2014.~~2015. Primary components of the change include the following:


	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2015 vs. 2014			2016 vs. 2015
	(in millions)			(in millions)
Hydro operations	$	10.8
Hydro operations - Kerr conveyance				$	(4.0	)
Non-employee directors deferred compensation	3.5			(2.9		)
Hydro Transaction costs	(0.6		)
Distribution System Infrastructure Project (DSIP) expenses				(1.7		)
Employee benefits				(1.5		)
Natural gas production gathering expense				(0.1		)
Bad debt expense	(0.5		)	1.0
Other	(2.0		)	(1.8		)
Increase in Operating, General & Administrative Expenses	$	11.2
Decrease in Operating, General & Administrative Expenses				$	(11.0	)

The ~~increase~~decrease in operating, general and administrative expenses ~~of $11.2 million was~~is primarily due to the following:

~~Hydro operating~~A decrease in hydro operations costs ~~associated with~~in the ~~November 2014 Hydro Transaction; and~~current period is a result of the conveyance of Kerr to the CSKT in September 2015 (offset by reduced revenue discussed above);

~~Non-employee~~The change in value of non-employee directors deferred compensation ~~increased as compared to the prior year, primarily~~ due to ~~an increase~~changes in our stock price during the three months ended September 30, 2015. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we account for the deferred shares as trading securities and their change in value is also reflected(offset by changes in other income with no impact on net ~~income.~~income);

Lower DSIP related expenses;

A decrease in employee benefit expense due to lower supplemental benefits costs; and

A decrease in natural gas production gathering expense (offset by lower gathering fees discussed above).

These ~~increases~~decreases were partly offset by ~~the following:~~

~~Lower legal and professional fees due to Hydro Transaction costs incurred in the prior period; and~~

~~Lower~~increased bad debt expense due to ~~improved~~timing on the collection of receivables from customers. In addition, company-wide cost control measures were implemented in 2016 and are included in Other.

Property and other taxes were ~~$35.7~~$40.7 million for the three months ended September 30, ~~2015,~~2016, as compared with ~~$27.8~~$35.7 million in the same period of ~~2014.~~2015. This increase was primarily due to plant additions and higher estimated property valuations in Montana, ~~which includes an estimated $6.4~~offset in part by a $0.3 million decrease from the ~~Hydro Transaction.~~conveyance of Kerr to the CSKT in September 2015. We estimate property taxes throughout each year, and update based on valuation reports received from the Montana Department of Revenue. In the third quarter of 2016, we increased our annual property tax expense estimate by approximately $5.4 million based on an updated valuation report. We update to ~~the~~ actual expense when we receive our Montana property tax bills in ~~November.~~November, and do not expect the November 2016 bills to be significantly different from our current estimate. 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. The MPSC has authorized recovery of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) as compared to the related amount included in rates during our last general rate case.

Depreciation and depletion expense was ~~$35.7~~$39.8 million for the three months ended September 30, ~~2015,~~2016, as compared with ~~$30.5~~$35.7 million in the same period of ~~2014.~~2015. This increase was primarily due to plant additions, including approximately ~~$4.1~~$1.4 million of ~~hydro related depreciation.~~depreciation associated with the Beethoven wind project acquisition.

Consolidated operating income for the three months ended September 30, ~~2015~~2016 was ~~$48.5~~$56.1 million as compared with ~~$31.0~~$48.5 million in the same period of ~~2014.~~2015. This increase was primarily due to the ~~impacts of our Hydro Transaction.~~increase in gross margin driven by the South Dakota rate increase as discussed above.

Consolidated interest expense for the three months ended September 30, ~~2015~~2016 was ~~$22.0~~$21.0 million, as compared with ~~$18.8~~$22.0 million in the same period of ~~2014.~~2015. This ~~increase~~decrease was primarily due to the debt refinancing transactions discussed above; partially offset by lower capitalization of allowance for funds used during construction (AFUDC) and increased debt outstanding associated with the ~~Hydro Transaction.~~September 2015 Beethoven wind project acquisition.

Consolidated other ~~income~~loss for the three months ended September 30, ~~2015,~~2016, was ~~$3.8~~$0.1 million as compared with ~~expense~~income of ~~$0.4~~$3.8 million in the same period of ~~2014.~~2015. This ~~increase~~decrease was primarily due to a ~~$3.5~~$2.9 million ~~increase~~decrease in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, ~~had~~is offset by a corresponding ~~increase~~decrease to operating, general and administrative expenses) and ~~higher~~lower capitalization of ~~allowance for funds used during construction (AFUDC).~~AFUDC.

Consolidated income tax ~~expense~~benefit for the three months ended September 30, ~~2015~~2016 was ~~$6.4~~$9.7 million, as compared with an income tax ~~benefit~~expense of ~~$18.4~~$6.4 million in the same period of ~~2014.~~2015. Our effective tax rate for the three months ended September 30, ~~2015~~2016 was ~~21.2%~~(27.6)% as compared with ~~(156.9)%~~21.2% for the same period of 2014. The income tax benefit in 2014 included the release of approximately $12.6 million of previously unrecognized tax benefits due to the lapse of statutes of limitation in the third quarter of 2014. In addition, during the third quarter of 2014, we elected the safe harbor method related to the deductibility of repair costs. This resulted in an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustments.2015. We currently expect our ~~2015~~2016 effective tax rate to range between ~~17%~~(3)% - ~~19%~~1%.

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



	Three Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	34.9				$	30.2

Income tax calculated at 35% federal statutory rate	12.2			35.0	%	10.6			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(0.6		)	(1.8	)	(0.9		)	(2.8	)
Flow-through repairs deductions	(19.0		)	(54.4	)	(2.8		)	(9.2	)
Production tax credits	(2.2		)	(6.3	)	(0.7		)	(2.4	)
Plant and depreciation of flow through items	(0.2		)	(0.7	)	(0.4		)	(1.2	)
Prior year permanent return to accrual adjustments	—			—		1.0			3.4
Other, net	0.1			0.6		(0.4		)	(1.6	)
	(21.9		)	(62.6	)	(4.2		)	(13.8	)

	$	(9.7	)	(27.6	)%	$	6.4		21.2	%

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. ~~The following table summarizes~~During the ~~differences between our effective~~third quarter of 2016, we filed a tax ~~rate~~accounting method change with the IRS related to costs to repair generation property, as discussed above in the overview. This resulted in an income tax benefit of approximately $15.5 million during the three months ended September 30, 2016, of which approximately $12.5 million is related to 2015 and prior tax years, and is reflected in the ~~federal statutory rate (in millions):~~flow-through repairs deductions line above.

Three Months Ended September 30,
2015 2014
Income Before Income Taxes $ 30.2
$ 11.8

Income tax calculated at 35% federal statutory rate 10.6
35.0 % 4.1
35.0 %

Permanent or flow through adjustments:
State income, net of federal provisions (0.9 ) (2.8 ) (0.1 ) (0.9 )
Release of unrecognized tax benefit —
—
(12.6 ) (107.3 )
Prior year permanent return to accrual adjustments 1.0
3.4
(5.2 ) (44.0 )
Flow-through repairs deductions (2.8 ) (9.2 ) (3.4 ) (29.0 )
Production tax credits (0.7 ) (2.4 ) (0.3 ) (2.6 )
Plant and depreciation of flow through items (0.4 ) (1.2 ) (0.7 ) (5.8 )
Other, net (0.4 ) (1.6 ) (0.2 ) (2.3 )
(4.2 ) (13.8 ) (22.5 ) (191.9 )

Income tax expense (benefit) $ 6.4
21.2 % $ (18.4 ) (156.9 )%

Consolidated net income for the three months ended September 30, ~~2015~~2016 was ~~$23.8~~$44.6 million as compared with ~~$30.2~~$23.8 million for the same period in ~~2014.~~2015. This ~~decrease~~increase was primarily due to anlower income ~~tax benefit included in our 2014 results~~taxes due to the ~~release~~adoption of ~~previously unrecognized~~a tax ~~benefits, partly offset by~~accounting method change and improved gross margin due to the ~~favorable impacts of our Hydro Transaction.~~South Dakota electric rate increase.

Nine Months Ended September 30, ~~2015~~2016 Compared with the Nine Months Ended September 30, ~~2014~~2015


	Nine Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Operating Revenues
Electric	$	695.9	$	653.0	$	42.9		6.6	%	$	756.4	$	695.9	$	60.5		8.7	%
Natural Gas	193.4		239.0		(45.6		)	(19.1	)	170.3		193.4		(23.1		)	(11.9	)
	$	889.3	$	892.0	$	(2.7	)	(0.3	)%
Total Operating Revenues										$	926.7	$	889.3	$	37.4		4.2	%


	Nine Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Cost of Sales
Electric	$	196.0	$	273.8	$	(77.8	)	(28.4	)%	$	245.5	$	196.0	$	49.5		25.3	%
Natural Gas	69.5		100.7		(31.2		)	(31.0	)	47.8		69.5		(21.7		)	(31.2	)
	$	265.5	$	374.5	$	(109.0	)	(29.1	)%
Total Cost of Sales										$	293.3	$	265.5	$	27.8		10.5	%


	Nine Months Ended September 30,									Nine Months Ended September 30,
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Gross Margin
Electric	$	499.9	$	379.2	$	120.7		31.8	%	$	510.9	$	499.9	$	11.0		2.2	%
Natural Gas	123.9		138.3		(14.4		)	(10.4	)	122.5		123.9		(1.4		)	(1.1	)
	$	623.8	$	517.5	$	106.3		20.5	%
Total Gross Margin										$	633.4	$	623.8	$	9.6		1.5	%

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

Gross Margin 2015 vs. 2014
(in millions)
Hydro operations $ 120.8
Property tax trackers
2.3
South Dakota electric interim rate increase (subject to refund)
1.8
Electric and natural gas retail volumes (10.4 )
Electric QF adjustment (4.3 )
Gas production deferral (1.6 )
Operating expenses recovered in trackers
(1.4 )
Other (0.9 )
Increase in Consolidated Gross Margin $ 106.3



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota electric rate increase	$	27.8
Lost revenue adjustment mechanism	8.8
Electric QF adjustment	6.1
Natural gas retail volumes	0.3
MPSC disallowance	(9.5		)
Electric transmission	(2.3		)
Natural gas production	(1.4		)
Electric retail volumes	(1.1		)
Other	(2.6		)
Change in Gross Margin Impacting Net Income	26.1

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(16.0		)
Production tax credits flowed-through trackers	(8.0		)
Natural gas production gathering fees	(1.1		)
Property taxes recovered in trackers	8.6
Change in Items Offset Within Net Income	(16.5		)
Increase in Consolidated Gross Margin	$	9.6

Consolidated gross margin for items impacting net income increased ~~$106.3~~$26.1 million, ~~primarily due to~~ which includes the following:

~~An increase in generation margin from the November 2014 Hydro Transaction;~~

~~An increase in property taxes included in trackers; and~~

An increase in South Dakota electric ~~rates implemented~~rates;

The recognition of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings, offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $5.4 million;

The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on ~~an interim basis~~a review of contract assumptions; and

An increase in ~~July 2015.~~our residential and commercial natural gas volumes due to colder late summer weather in our Montana jurisdiction and customer growth, partly offset by warmer winter and spring weather.

These increases were partly offset by:

The MPSC disallowance of previously incurred replacement power and modeling/planning costs as discussed above;

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

A decrease in natural gas production margin due to a $0.7 million decrease in interim rates based on actual costs and a $0.7 million decrease in overhead fees; and

A decrease in electric ~~and natural gas~~ retail volumes due primarily to ~~the seasonal impacts~~warmer winter weather and colder late summer weather in our Montana jurisdiction, along with lower industrial volumes of ~~milder weather,~~a large Montana customer, partly offset by warmer spring and summer weather in our South Dakota jurisdiction and customer ~~growth;~~growth.

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

A ~~$6.1 million~~decrease in revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);

A decrease in revenues for production tax credits primarily associated with the Beethoven wind generation project, which is a reduction in our customers rates (offset by reduced income tax expense);

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

An increase in the QF liability recorded in the second quarter of 2015 based on a review of contract assumptions in our estimated liability, partly offset by $1.8 million lower QF related supply costs based on actual QF pricing and output;

~~A deferral of interim gas production revenue based on actual costs; and~~

~~Lower~~ revenues for ~~operating expenses recovered~~property taxes included in trackers ~~primarily related to customer efficiency programs.~~(offset by increased property tax expense).


	Nine Months Ended September 30,								Nine Months Ended September 30,
	2015		2014		Change		% Change		2016		2015		Change			% Change
	(dollars in millions)								(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	222.1	$	214.6	$	7.5	3.5	%	$	220.7	$	222.1	$	(1.4	)	(0.6	)%
Property and other taxes	101.0		84.3		16.7		19.8		111.3		101.0		10.3			10.2
Depreciation and depletion	107.2		91.1		16.1		17.7		119.6		107.2		12.4			11.6
	$	430.3	$	390.0	$	40.3	10.3	%	$	451.6	$	430.3	$	21.3		5.0	%

Consolidated operating, general and administrative expenses were $220.7 million for the nine months ended September 30, 2016, as compared with $222.1 million for the nine months ended September 30, ~~2015, as compared with $214.6 million for the nine months ended~~ ~~September 30, 2014~~.2015. Primary components of the change include the following:

Operating, General & Administrative Expenses
2015 vs. 2014
(in millions)
Hydro operations $ 32.7
Employee benefit and compensation costs 3.6
Insurance recovery, net (20.8 )
Bad debt expense (3.3 )
Hydro Transaction costs (2.3 )
Non-employee directors deferred compensation (1.4 )
Operating expenses recovered in trackers
(1.4 )
Other 0.4
Increase in Operating, General & Administrative Expenses $ 7.5



	Operating, General & Administrative Expenses
	2016 vs. 2015
	(in millions)
Hydro operations - Kerr conveyance	$	(15.2	)
DSIP expenses	(3.3		)
Employee benefits	(1.5		)
Bad debt expense	(1.2		)
Natural gas production gathering expense	(1.1		)
Insurance recovery, net	20.8
Non-employee directors deferred compensation	1.8
Insurance reserves	0.9
Other	(2.6		)
Decrease in Operating, General & Administrative Expenses	$	(1.4	)

The ~~increase~~decrease in operating, general and administrative expenses of ~~$7.5 million~~ ~~was~~is primarily due to hydro operating costs associated with the November 2014 Hydro Transaction and higher employee benefit costs primarily due to higher medical expense and compensation costs. These increases were partly offset by the following:

A ~~net~~decrease in hydro operations costs in the current period as a result of the conveyance of Kerr to the CSKT in September 2015 (offset by reduced revenue discussed above);

Lower DSIP related expenses;

A decrease in employee benefits expense due to lower supplemental benefits costs;

Lower bad debt expense, due to improved collection of receivables from customers; and

A decrease in natural gas production gathering expense (offset by lower gathering fees discussed above).

These decreases were offset in part by:

The inclusion in our second quarter 2015 results of an insurance recovery, primarily associated with electric generation related environmental remediation costs incurred in prior periods;

~~Lower bad debt expense, due to improved collection~~The change in value of ~~receivables from customers;~~

~~Lower legal and professional fees due to Hydro Transaction costs incurred in the prior period;~~

~~Non-employee~~non-employee directors deferred compensation ~~decreased as compared to the prior year, primarily~~ due to ~~a decrease~~changes in our stock price ~~during~~(offset by changes in other income with no impact on net income); and

An increase in insurance reserves primarily due to the ~~nine months ended September 30, 2015; and~~Billings, Montana refinery outage discussed in Note 13 to the Financial Statements.

~~Lower revenue for operating expenses recovered through our supply trackers, primarily related to efficiency~~

In addition, cost control measures implemented in 2016 are included in Other.

~~implemented by customers.~~

Property and other taxes were ~~$101.0~~$111.3 million for the nine months ended September 30, ~~2015,~~2016, as compared with ~~$84.3~~$101.0 million in the same period of ~~2014.~~2015. This increase was primarily due to plant additions and higher estimated property valuations in Montana, ~~which includes an estimated $13.8~~offset in part by a $0.8 million decrease from the ~~Hydro Transaction.~~conveyance of Kerr to the CSKT in September 2015.

Depreciation and depletion expense was ~~$107.2~~$119.6 million for the nine months ended September 30, ~~2015,~~2016, as compared with ~~$91.1~~$107.2 million in the same period of ~~2014.~~2015. This increase was primarily due to plant additions, including approximately ~~$12.4~~$4.2 million of ~~hydro related depreciation.~~depreciation associated with the September 2015 Beethoven wind project acquisition.

Consolidated operating income for the nine months ended September 30, ~~2015~~2016 was ~~$193.5~~$181.8 million, as compared with ~~$127.4~~$193.5 million in the same period of ~~2014.~~2015. This ~~increase~~decrease was primarily due to the ~~Hydro Transaction and~~$20.8 million insurance recovery in 2015, partly offset by higher gross margin as discussed above.

Consolidated interest expense for the nine months ended September 30, ~~2015~~2016 was ~~$68.1~~$72.0 million, as compared with ~~$57.9~~$68.1 million in the same period of ~~2014~~.2015. This increase was primarily due to $2.9 million of interest associated with the MPSC disallowance as discussed above, lower capitalization of allowance for funds used during construction (AFUDC), and increased debt outstanding associated with the ~~Hydro Transaction.~~Beethoven wind project acquisition, partly offset by the debt refinancing transactions discussed above.

Consolidated other income for the nine months ended September 30, ~~2015~~,2016, was ~~$5.4~~$4.2 million, as compared with ~~$4.7~~$5.4 million in the same period of ~~2014~~.2015. This ~~increase~~decrease was primarily due to ~~higher~~lower capitalization of AFUDC, ~~partially~~partly offset by a ~~$1.4~~$1.8 million ~~reduction~~increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, ~~had~~is offset by a corresponding ~~reduction~~increase to operating, general and administrative expenses).

Consolidated income tax ~~expense~~benefit for the nine months ended September 30, ~~2015~~2016 was ~~$24.6~~$4.2 million, as compared with ana income tax ~~benefit~~expense of ~~$9.2~~$24.6 million in the same period of ~~2014. This increase was due to higher pre-tax income and an increase in our~~2015. Our effective tax rate ~~to 18.8%~~ for the nine months ended September 30, ~~2015~~2016 was (3.7)% as compared with ~~(12.4)%~~18.8% for the ~~nine months ended September 30, 2014. The income tax benefit in 2014 was primarily a result~~same period of ~~the release of previously unrecognized tax benefits due to the lapse of statutes of limitation in the third quarter of 2014.~~


	Nine Months Ended September 30,										Nine Months Ended September 30,
	2015					2014					2016					2015
Income Before Income Taxes	$	130.8				$	74.3				$	114.0				$	130.8

Income tax calculated at 35% federal statutory rate	45.8			35.0	%	26.0			35.0	%	39.9			35.0	%	45.8			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(0.3		)	(0.3	)	0.3			0.3		(2.7		)	(2.4	)	(0.3		)	(0.3	)
Flow-through repairs deductions	(17.2		)	(13.2	)	(14.9		)	(20.0	)	(32.7		)	(28.6	)	(17.2		)	(13.2	)
Release of unrecognized tax benefit	—			—		(12.6		)	(17.0	)
Prior year permanent return to accrual adjustments	1.0			0.8		(5.2		)	(7.0	)
Production tax credits	(2.6		)	(2.0	)	(2.1		)	(2.8	)	(7.3		)	(6.4	)	(2.6		)	(2.0	)
Plant and depreciation of flow through items	(1.0		)	(0.8	)	(0.2		)	(0.2	)	(1.4		)	(1.3	)	(1.0		)	(0.8	)
Prior year permanent return to accrual adjustments											(0.1		)	(0.1	)	1.0			0.8
Other, net	(1.1		)	(0.7	)	(0.5		)	(0.7	)	0.1			0.1		(1.1		)	(0.7	)
	(21.2		)	(16.2	)	(35.2		)	(47.4	)	(44.1		)	(38.7	)	(21.2		)	(16.2	)

Income tax expense (benefit)	$	24.6		18.8	%	$	(9.2	)	(12.4	)%
											$	(4.2	)	(3.7	)%	$	24.6		18.8	%

The 2016 benefit reflects the adoption of a tax accounting method change during the third quarter of 2016 related to costs to repair generation property, as discussed above.

Consolidated net income for the nine months ended September 30, ~~2015~~2016 was ~~$106.2~~$118.2 million as compared with ~~$83.5~~$106.2 million for the same period in ~~2014~~.2015. This increase was primarily due to ~~the Hydro Transaction and insurance recovery~~lower income taxes as discussed above, and improved gross margin, partly offset by ~~an income tax benefit included~~the inclusion in our ~~2014~~2015 results ~~due to the release~~ of ~~previously unrecognized tax benefits.~~a $20.8 million insurance recovery and higher interest 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.

~~Regulation~~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.

~~Other: Miscellaneous~~Wholesale and other: In October 2015, we became a member of the Southwest Power Pool (SPP), which is a regional transmission organization. As a market participant in SPP, we buy and sell wholesale energy and reserves through the operation of a single, consolidated SPP balancing authority. As such, the increase in wholesale revenues is offset through an increase in cost of sales. This line also includes miscellaneous electric revenues.

Three Months Ended September 30, ~~2015~~2016 Compared with the Three Months Ended September 30, ~~2014~~2015


	Results										Results
	2015		2014			Change			% Change		2016		2015		Change			% Change
	(dollars in millions)										(dollars in millions)
Retail revenues	$	208.2	$	197.9		$	10.3		5.2	%	$	219.3	$	208.2	$	11.1		5.3	%
Regulatory amortization	12.5		(2.3		)	14.8			643.5		2.3		12.5		(10.2		)	(81.6	)
Total retail revenues	220.7		195.6			25.1			12.8		221.6		220.7		0.9			0.4
Transmission	13.8		14.7			(0.9		)	(6.1	)	13.4		13.8		(0.4		)	(2.9	)
Regulation services	0.4		0.3			0.1			33.3
Other	3.6		1.8			1.8			100.0
Ancillary services											0.4		0.4		—			—
Wholesale and other											31.2		3.6		27.6			766.7
Total Revenues	238.5		212.4			26.1			12.3		266.6		238.5		28.1			11.8
Total Cost of Sales	66.2		84.7			(18.5		)	(21.8	)	89.7		66.2		23.5			35.5
Gross Margin	$	172.3	$	127.7		$	44.6		34.9	%	$	176.9	$	172.3	$	4.6		2.7	%


	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014	2016		2015		2016	2015	2016	2015
	(in thousands)								(in thousands)
Retail Electric
Montana	$	65,296	$	59,545	559	545	287,708	283,412	$	67,346	$	65,296	559	559	291,628	287,708
South Dakota	13,376		12,527		142	132	49,811	49,581	16,426		13,376		151	142	50,044	49,811
Residential	78,672		72,072		701	677	337,519	332,993	83,772		78,672		710	701	341,672	337,519
Montana	86,942		84,726		827	826	64,873	63,906	88,932		86,942		813	827	65,702	64,873
South Dakota	20,679		19,963		259	251	12,571	12,451	24,254		20,679		268	259	12,665	12,571
Commercial	107,621		104,689		1,086	1,077	77,444	76,357	113,186		107,621		1,081	1,086	78,367	77,444
Industrial	10,420		10,329		558	559	75	77	9,937		10,420		555	558	75	75
Other	11,455		10,805		91	86	7,952	8,031	12,377		11,455		97	91	8,010	7,952
Total Retail Electric	$	208,168	$	197,895	2,436	2,399	422,990	417,458	$	219,272	$	208,168	2,443	2,436	428,124	422,990



	Cooling Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	241	275	273	12% colder	12% colder
South Dakota	739	650	634	14% warmer	17% warmer

Degree Days 2015 as compared with:
Cooling Degree-Days 2015 2014 Historic Average 2014 Historic Average
Montana 275 324 273 15% cooler 1% warmer
South Dakota 650 467 635 39% warmer 2% warmer


	Degree Days			2015 as compared with:		Heating Degree Days			2016 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
						2016	2015	Historic Average	2015	Historic Average
Montana	340	330	342	3% cooler	1% warmer	413	340	336	21% colder	23% colder
South Dakota	73	107	83	32% warmer	12% warmer	42	73	83	42% warmer	49% warmer

The following summarizes the components of the changes in electric gross margin for the three months ended September 30, ~~2015~~2016 and ~~2014~~2015:

Gross Margin 2015 vs. 2014
(in millions)
Hydro operations $ 40.4
South Dakota interim rate increase (subject to refund)
1.8
Property tax tracker 1.3
Electric retail volumes 1.1
Operating expenses recovered in trackers
0.9
Electric transmission capacity (0.9 )
Increase in Gross Margin $ 44.6



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota rate increase	$	9.2
Lost revenue adjustment mechanism	(1.8		)
Retail volumes	(0.4		)
Transmission	(0.4		)
Other	0.5
Change in Gross Margin Impacting Net Income	7.1

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(4.3		)
Production tax credits flowed-through trackers	(2.1		)
Property taxes recovered in trackers	3.9
Change in Items Offset Within Net Income	(2.5		)
Increase in Consolidated Gross Margin	$	4.6

~~This increase in gross~~Gross margin ~~was primarily due to~~for items impacting net income increased $7.1 million including the following:

An increase in ~~generation margin from the November 2014 Hydro Transaction;~~

~~An increase in~~ South Dakota ~~rates implemented on an interim basis in July 2015;~~electric rates; partly offset by

~~An increase in property taxes included in trackers;~~The elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs;

~~An increase~~A decrease in electric retail volumes due primarily to colder late summer weather in Montana, along with lower industrial volumes of a large Montana customer; partly offset by customer growth ~~in the residential and commercial categories~~ and warmer summer weather in South Dakota; and

~~Higher revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs.~~

~~These increases were partly offset by lower~~Lower demand to transmit energy across our transmission lines due to market pricing and other conditions.

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

A decrease in revenues ~~cover~~from the ~~costs of operating utility assets, paying taxes and interest, and earning a return on our shareholders’ investments. As a result~~conveyance of the ~~Hydro Transaction, we also earn~~Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);

A decrease in revenues for production tax credits primarily associated with the Beethoven wind generation project, which is a ~~return on these assets, thereby increasing revenue.~~reduction in our customers rates (offset by reduced income tax expense); and

An increase in revenues for property taxes included in trackers (offset by increased property tax expense).

~~Our cost of sales are lower due to reduced market purchases of power, which are passed through to retail customers at actual cost with no return component. In addition, the increase~~The change in regulatory amortization revenue is 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.

Nine Months Ended September 30, ~~2015~~2016 Compared with the Nine Months Ended September 30, ~~2014~~2015


	Results									Results
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	621.9	$	583.7	$	38.2		6.5	%	$	630.0	$	621.9	$	8.1		1.3	%
Regulatory amortization	23.1		21.6		1.5			6.9		15.1		23.1		(8.0		)	(34.6	)
Total retail revenues	645.0		605.3		39.7			6.6		645.1		645.0		0.1			—
Transmission	41.1		40.8		0.3			0.7		38.8		41.1		(2.3		)	(5.6	)
Regulation services	1.2		1.2		—			—
Other	8.6		5.7		2.9			50.9
Ancillary services										1.2		1.2		—			—
Wholesale and other										71.3		8.6		62.7			729.1
Total Revenues	695.9		653.0		42.9			6.6		756.4		695.9		60.5			8.7
Total Cost of Sales	196.0		273.8		(77.8		)	(28.4	)	245.5		196.0		49.5			25.3
Gross Margin	$	499.9	$	379.2	$	120.7		31.8	%	$	510.9	$	499.9	$	11.0		2.2	%


	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts		Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014	2016		2015		2016	2015	2016	2015
	(in thousands)								(in thousands)
Retail Electric
Montana	$	206,284	$	192,303	1,732	1,773	286,854	282,836	$	207,080	$	206,284	1,748	1,732	290,807	286,854
South Dakota	38,031		39,049		434	453	49,774	49,548	44,305		38,031		433	434	49,967	49,774
Residential	244,315		231,352		2,166	2,226	336,628	332,384	251,385		244,315		2,181	2,166	340,774	336,628
Montana	262,367		242,274		2,401	2,410	64,594	63,658	257,566		262,367		2,381	2,401	65,467	64,594
South Dakota	56,552		56,343		739	738	12,467	12,322	65,454		56,552		749	739	12,591	12,467
Commercial	318,919		298,617		3,140	3,148	77,061	75,980	323,020		318,919		3,130	3,140	78,058	77,061
Industrial	33,412		30,612		1,697	1,642	75	75	29,626		33,412		1,628	1,697	74	75
Other	25,250		23,154		167	156	6,252	6,260	25,993		25,250		170	167	6,300	6,252
Total Retail Electric	$	621,896	$	583,735	7,170	7,172	420,016	414,699	$	630,024	$	621,896	7,109	7,170	425,206	420,016


	Degree Days			2015 as compared with:		Cooling Degree Days			2016 as compared with:
Cooling Degree-Days	2015	2014	Historic Average	2014	Historic Average
						2016	2015	Historic Average	2015	Historic Average
Montana	382	332	314	15% warmer	22% warmer	313	382	316	18% colder	1% colder
South Dakota	719	544	699	32% warmer	3% warmer	837	719	696	16% warmer	20% warmer


	Degree Days			2015 as compared with:		Heating Degree Days			2016 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
						2016	2015	Historic Average	2015	Historic Average
Montana	4,328	5,049	4,937	14% warmer	12% warmer	4,411	4,328	4,906	2% colder	10% warmer
South Dakota	5,342	6,265	5,612	15% warmer	5% warmer	4,962	5,342	5,631	7% warmer	12% warmer

The following summarizes the components of the changes in electric gross margin for the nine months ended September 30, ~~2015~~2016 and ~~2014:~~

2015:

Gross Margin 2015 vs. 2014
(in millions)
Hydro operations $ 120.8
Property tax trackers
2.3
South Dakota interim rate increase (subject to refund)
1.8
QF adjustment (4.3 )
Retail volumes (1.7 )
Other 1.8
Increase in Gross Margin $ 120.7



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota rate increase	$	27.8
Lost revenue adjustment mechanism	8.2
QF adjustment	6.1
MPSC disallowance	(9.5		)
Transmission	(2.3		)
Retail volumes	(1.1		)
Other	(1.4		)
Change in Gross Margin Impacting Net Income	27.8

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(16.0		)
Production tax credits flowed-through trackers	(8.0		)
Property taxes recovered in trackers	7.2
Change in Items Offset Within Net Income	(16.8		)
Increase in Consolidated Gross Margin	$	11.0

~~This increase in gross~~Gross margin ~~was primarily due to~~for items impacting net income increased $27.8 million including the following:

An increase in ~~generation margin from~~South Dakota electric rates;

The recognition of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings, offset in part by the ~~November 2014 Hydro Transaction;~~elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs; and

AnThe inclusion in our 2015 results of an increase in ~~property taxes included in trackers; and~~

~~An increase in South Dakota rates implemented~~supply costs due to the adjustment of the QF liability based on ~~an interim basis in July 2015.~~a review of contract assumptions.

These increases were partly offset ~~by:~~by;

The MPSC disallowance of previously incurred costs as discussed above;

~~A $6.1 million increase in the QF liability recorded in the second quarter of 2015 based on a review of contract assumptions in~~Lower demand to transmit energy across our ~~estimated liability, partly offset by $1.8 million lower QF related supply costs based on actual QF~~transmission lines due to market pricing and ~~output;~~other conditions; and

A decrease in electric retail volumes due primarily to warmer winter weather and colder late summer weather in our Montana jurisdiction, along with lower industrial volumes of a large Montana customer, partly offset by warmer spring ~~weather, customer growth~~ and ~~warmer~~ summer weather in our South Dakota ~~as compared with the same period of 2014.~~jurisdiction and customer growth.

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

A decrease in revenues from the conveyance of ~~sales are lower due~~the Kerr facility to the CSKT in September 2015 (offset by reduced ~~market purchases of power,~~operating expenses);

A decrease in revenues for production tax credits associated with the Beethoven wind generation project, which ~~are passed through to retail~~is a reduction in our customers ~~at actual cost with no return component.~~ rates (offset by reduced income tax expense); and

An increase in revenues for property taxes included in trackers (offset by increased property tax expense).

In addition, the ~~increase~~change in regulatory amortization revenue is 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 September 30, ~~2015~~2016 Compared with the Three Months Ended September 30, ~~2014~~2015


	Results									Results
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	20.7	$	25.4	$	(4.7	)	(18.5	)%	$	21.1	$	20.7	$	0.4		1.9	%
Regulatory amortization	4.0		4.0		—			—		3.6		4.0		(0.4		)	(10.0	)
Total retail revenues	24.7		29.4		(4.7		)	(16.0	)	24.7		24.7		—			—
Wholesale and other	9.5		10.1		(0.6		)	(5.9	)	9.7		9.5		0.2			2.1
Total Revenues	34.2		39.5		(5.3		)	(13.4	)	34.4		34.2		0.2			0.6
Total Cost of Sales	7.4		9.9		(2.5		)	(25.3	)	6.5		7.4		(0.9		)	(12.2	)
Gross Margin	$	26.8	$	29.6	$	(2.8	)	(9.5	)%	$	27.9	$	26.8	$	1.1		4.1	%


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014	2016		2015		2016	2015	2016	2015
	(in thousands)								(in thousands)
Retail Gas
Montana	$	9,227	$	11,057	832	904	165,829	163,474	$	9,607	$	9,227	901	832	167,909	165,829
South Dakota	1,770		2,051		113	116	38,523	38,196	1,699		1,770		108	113	38,907	38,523
Nebraska	1,886		2,299		148	154	36,662	36,480	1,796		1,886		145	148	36,888	36,662
Residential	12,883		15,407		1,093	1,174	241,014	238,150	13,102		12,883		1,154	1,093	243,704	241,014
Montana	5,219		6,567		579	596	22,810	22,580	5,691		5,219		623	579	23,108	22,810
South Dakota	1,397		1,726		228	210	6,225	6,105	1,248		1,397		213	228	6,401	6,225
Nebraska	1,026		1,457		174	194	4,599	4,571	904		1,026		174	174	4,688	4,599
Commercial	7,642		9,750		981	1,000	33,634	33,256	7,843		7,642		1,010	981	34,197	33,634
Industrial	130		135		17	13	262	260	109		130		13	17	257	262
Other	66		102		9	10	153	153	87		66		11	9	157	153
Total Retail Gas	$	20,721	$	25,394	2,100	2,197	275,063	271,819	$	21,141	$	20,721	2,188	2,100	278,315	275,063


	Degree Days			2015 as compared with:		Heating Degree Days			2016 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
						2016	2015	Historic Average	2015	Historic Average
Montana	340	330	342	3% cooler	1% warmer	413	340	336	21% colder	23% colder
South Dakota	73	107	83	32% warmer	12% warmer	42	73	83	42% warmer	49% warmer
Nebraska	27	63	44	57% warmer	39% warmer	22	27	43	19% warmer	49% warmer

The following summarizes the components of the changes in natural gas gross margin for the three months ended September 30, ~~2015~~2016 and ~~2014~~2015:

Gross Margin 2015 vs. 2014
(in millions)
Operating expenses recovered in trackers
$ (0.6 )
Retail volumes (0.5 )
Gas production deferral (0.4 )
Other (1.3 )
Decrease in Gross Margin $ (2.8 )



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	1.4
Production	(0.2		)
Other	(0.8		)
Change in Gross Margin Impacting Net Income	0.4

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	0.8
Production gathering fees	(0.1		)
Change in Items Offset Within Net Income	0.7
Increase in Consolidated Gross Margin	$	1.1

~~This~~Gross margin for items impacting net income increased $0.4 million including the following:

An increase in retail volumes due primarily to colder late summer weather in our Montana jurisdiction and customer growth; partly offset by

A decrease in production margin due to lower overhead fees.

The change in gross margin ~~was primarily due to lower revenue~~also includes the following items that had no impact on net income:

An increase in revenues for ~~operating expenses recovered through our supply~~property taxes included in trackers ~~primarily related to efficiency measures implemented~~(offset by ~~customers, a~~increased property tax expense); and

A decrease in ~~residential~~production gathering fees (offset by reduced operating expenses).

Our wholesale and ~~commercial retail volumes, and a deferral of initial interim gas production rate revenue compared to actual costs. In addition, average natural gas supply prices decreased~~other revenues are largely gross margin neutral as they are offset by changes in ~~2015 resulting in lower retail revenues and~~ cost of ~~sales as compared with 2014, with no impact to gross margin.~~sales.

Nine Months Ended September 30, ~~2015~~2016 Compared with the Nine Months Ended September 30, ~~2014~~2015


	Results									Results
	2015		2014		Change			% Change		2016		2015		Change			% Change
	(dollars in millions)									(dollars in millions)
Retail revenues	$	159.3	$	202.7	$	(43.4	)	(21.4	)%	$	138.1	$	159.3	$	(21.2	)	(13.3	)%
Regulatory amortization	3.4		3.7		(0.3		)	8.1		3.1		3.4		(0.3		)	(8.8	)
Total retail revenues	162.7		206.4		(43.7		)	(21.2	)	141.2		162.7		(21.5		)	(13.2	)
Wholesale and other	30.7		32.6		(1.9		)	(5.8	)	29.1		30.7		(1.6		)	(5.2	)
Total Revenues	193.4		239.0		(45.6		)	(19.1	)	170.3		193.4		(23.1		)	(11.9	)
Total Cost of Sales	69.5		100.7		(31.2		)	(31.0	)	47.8		69.5		(21.7		)	(31.2	)
Gross Margin	$	123.9	$	138.3	$	(14.4	)	(10.4	)%	$	122.5	$	123.9	$	(1.4	)	(1.1	)%


	Revenues				Dekatherms (Dkt)		Customer Counts		Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014	2016		2015		2016	2015	2016	2015
	(in thousands)								(in thousands)
Retail Gas
Montana	$	64,724	$	86,186	7,420	8,460	165,801	163,662	$	60,160	$	64,724	7,622	7,420	167,901	165,801
South Dakota	19,944		22,820		2,151	2,553	38,770	38,490	15,827		19,944		1,982	2,151	39,115	38,770
Nebraska	16,964		19,528		1,851	2,116	36,894	36,787	13,040		16,964		1,703	1,851	37,077	36,894
Residential	101,632		128,534		11,422	13,129	241,465	238,939	89,027		101,632		11,307	11,422	244,093	241,465
Montana	33,140		44,869		4,003	4,840	22,924	22,707	30,673		33,140		4,070	4,003	23,190	22,924
South Dakota	13,529		16,670		2,096	2,322	6,268	6,138	10,200		13,529		1,984	2,096	6,428	6,268
Nebraska	9,564		10,862		1,414	1,580	4,639	4,619	6,850		9,564		1,310	1,414	4,714	4,639
Commercial	56,233		72,401		7,513	8,742	33,831	33,464	47,723		56,233		7,364	7,513	34,332	33,831
Industrial	855		920		109	96	263	262	698		855		98	109	260	263
Other	621		856		89	104	152	153	662		621		103	89	157	152
Total Retail Gas	$	159,341	$	202,711	19,133	22,071	275,711	272,818	$	138,110	$	159,341	18,872	19,133	278,842	275,711


	Degree Days			2015 as compared with:		Heating Degree Days			2016 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
						2016	2015	Historic Average	2015	Historic Average
Montana	4,328	5,049	4,937	14% warmer	12% warmer	4,411	4,328	4,906	2% colder	10% warmer
South Dakota	5,342	6,265	5,612	15% warmer	5% warmer	4,962	5,342	5,631	7% warmer	12% warmer
Nebraska	4,382	4,775	4,614	8% warmer	5% warmer	4,011	4,382	4,630	8% warmer	13% warmer

The following summarizes the components of the changes in natural gas gross margin for the nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:

Gross Margin 2015 vs. 2014
(in millions)
Retail volumes $ (8.7 )
Gas production deferral (1.6 )
Operating expenses recovered in trackers
(1.2 )
Other (2.9 )
Decrease in Gross Margin $ (14.4 )



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Production	$	(1.4	)
Lost revenue adjustment mechanism	0.6
Retail volumes	0.3
Other	(1.2		)
Change in Gross Margin Impacting Net Income	(1.7		)

Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	1.4
Production gathering fees	(1.1		)
Change in Items Offset Within Net Income	0.3
Decrease in Consolidated Gross Margin	$	(1.4	)

~~This~~Gross margin for items impacting net income decreased $1.7 million including the following:

A decrease in ~~gross~~production margin ~~and volumes was primarily~~ due to ~~the same reasons discussed in the three months ended section above, with~~ a $0.7 million decrease in interim rates based on actual costs and a $0.7 million decrease in overhead fees; partly offset by

The recognition of deferred revenue as a result of a MPSC final order in our tracker filings, which was offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs; and

An increase in residential and commercial retail volumes ~~from~~due to colder late summer weather in our Montana jurisdiction and customer growth, partly offset by warmer winter and spring weather.

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

An increase in revenues for property taxes included in trackers (offset by increased property tax expense); and

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

In addition, average natural gas supply prices decreased in ~~2015~~2016 resulting in lower retail revenues and cost of sales as compared with ~~2014,~~2015, with no impact to gross margin. ~~The decrease~~Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in ~~regulatory amortization revenue is due to timing differences between when we incur natural gas supply costs and when we recover these costs in rates from our customers.~~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~~expect to maintain a 50 - 55 percent debt to total capital ratio excluding capital leases, and ~~expect to~~ continue targeting 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 September 30, ~~2015~~2016, our total net liquidity was approximately ~~$142.2~~$132.8 million,, including ~~$10.1~~$5.1 million of cash and ~~$132.1~~$127.7 million of revolving credit facility availability. Revolving credit facility availability was ~~$196.1~~$136.2 millionas of October ~~16, 2015~~14, 2016.~~. We financed~~

During the ~~Beethoven wind project acquisition with a combination~~second quarter of ~~$70~~2016, we issued $60 million of South Dakota ~~first mortgage bonds, approximately $57~~First Mortgage Bonds. Proceeds were used to redeem $55 million of ~~equity and~~First Mortgage Bonds due in 2018. During the ~~remainder with short-term borrowings. The $70~~third quarter of 2016, the City of Forsyth, Montana, issued on our behalf $144.7 million aggregate principal amount of ~~South Dakota first mortgage bonds were issued in September 2015~~Pollution Control Revenue Refunding Bonds at a fixed interest rate of ~~4.26%~~2.00% maturing in ~~2040. The equity transaction was completed in October 2015 through~~2023. Proceeds from the issuance and available funds were used to redeem the City of ~~1,100,000 shares~~Forsyth's 4.65%, $170.2 million Pollution Control Revenue Bonds due 2023. Also during the third quarter of ~~our common stock~~2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at ~~$51.81 per share.~~a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes.

The following table presents additional information about short term borrowings during the three months ended September 30, ~~2015~~2016 (in millions):


Amount outstanding at period end	$	217.9	$	222.3
Daily average amount outstanding	$	174.1	$	257.3
Maximum amount outstanding	$	266.9	$	284.7

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 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.

As of September 30, ~~2015~~2016, we are under collected on our ~~natural gas and electric~~supply trackers by approximately ~~$15.0~~$5.1 million,, as compared with an under collection of ~~$33.0~~$29.4 million as of December 31, ~~2014,~~2015, and ~~an under collection of $31.9~~$15.0 million as of September 30, ~~2014~~2015.

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 Investors Service (Moody's) and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of October ~~16, 2015,~~14, 2016, 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	A1	A3	Prime-2	~~Stable~~Negative
S&P	A-	BBB	A-2	Stable

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):


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2016			2015
Operating Activities
Net income	$	106.2		$	83.5		$	118.2		$	106.2
Non-cash adjustments to net income	132.2			123.0			117.1			132.2
Changes in working capital	65.1			36.5			28.9			65.1
Other	0.9			(38.1		)
	304.4			204.9
Other noncurrent assets and liabilities							(6.2		)	0.9
Cash Provided by Operating Activities							258.0			304.4

Investing Activities
Property, plant and equipment additions	(203.3		)	(186.1		)	(204.0		)	(203.3		)
Acquisitions	(143.3		)	1.4			—			(143.3		)
Proceeds from sale of assets	30.2			0.4			1.4			30.2
Change in restricted cash	11.7			(21.2		)	—			11.7
Investment in New Market Tax Credit program	—			(18.2		)
	(304.7		)	(223.7		)
Cash Used in Investing Activities							(202.6		)	(304.7		)

Financing Activities
Proceeds from issuance of common stock, net	—			13.3
Issuances of long-term debt, net	120.0			25.7			24.5			120.0
(Repayments) issuances of short-term borrowings, net	(49.9		)	29.0
Repayments of short-term borrowings, net							(7.6		)	(49.9		)
Dividends on common stock	(67.1		)	(46.4		)	(71.8		)	(67.1		)
Financing costs	(12.1		)	(0.8		)	(6.6		)	(12.1		)
Other	(0.9		)	(0.9		)	(0.8		)	(0.9		)
Cash Used in Financing Activities							(62.3		)	(10.0		)
	(10.0		)	19.9

(Decrease) Increase in Cash and Cash Equivalents	$	(10.3	)	$	1.1
Decrease in Cash and Cash Equivalents							$	(6.9	)	$	(10.3	)
Cash and Cash Equivalents, beginning of period	$	20.4		$	16.6		$	12.0		$	20.4
Cash and Cash Equivalents, end of period	$	10.1		$	17.7		$	5.1		$	10.1

Cash Provided by Operating Activities

As of September 30, ~~2015~~2016, cash and cash equivalents were $~~10.1~~5.1 million as compared with $~~20.4~~12.0 million at December 31, ~~2014~~2015 and $~~17.7~~10.1 million at September 30, ~~2014~~2015. Cash provided by operating activities totaled $~~304.4~~258.0 million for the nine months ended September 30, ~~2015~~2016 as compared with $~~204.9~~304.4 million during the nine months ended September 30, ~~2014.~~2015. This ~~increase~~decrease in operating cash flows is primarily due to ~~higher net income adjusted for noncash depreciation, primarily due~~refunds associated with the DGGS FERC ruling and the South Dakota electric rate case of approximately $30.8 million and $7.2 million, respectively, to ~~the results of the Hydro Transaction, and a reduction in our under collection of supply costs in our trackers~~customers during the ~~current period that impacted working capital. This increase was~~first nine months of 2016, offset in part by ~~an $18.4 million settlement of interest rate swaps~~improved collections from customers during the ~~first quarter of 2015.~~prior period.

Cash Used in Investing Activities

Cash used in investing activities ~~increased~~decreased by approximately $~~81.0~~102.0 million as compared with the first nine months of ~~2014.~~2015. Plant additions during 2016 include maintenance additions of approximately $109.4 million, capacity related capital expenditures of approximately $56.2 million, and infrastructure capital expenditures of approximately $38.4 million. During September 2015, we completed the purchase of the 80 MW Beethoven wind project in South Dakota for approximately $143 million. Plant additions during the first nine months of 2015 ~~include~~included maintenance additions of approximately ~~$139.7~~$139.7 million,, supply related capital expenditures of approximately ~~$23.5~~$23.5 million,, primarily related to electric generation facilities in South Dakota, and ~~Distribution System Infrastructure Project (DSIP)~~infrastructure capital expenditures of approximately ~~$40.1 million~~.$40.1 million. Partially offsetting the impact of these expenditures was the receipt of $30 million for the sale of the Kerr Project. ~~Plant additions during the first nine months of 2014 include maintenance additions of approximately $117.9 million, supply related capital~~

~~expenditures of approximately $30.2 million, which were primarily related to electric generation facilities in South Dakota, and DSIP capital expenditures of approximately $38.0 million.~~

Cash ~~Provided by (Used in)~~Used in Financing Activities

Cash used in financing activities totaled ~~approximately~~ $~~10.0~~62.3 million during the nine months ended September 30, ~~2015~~2016 as compared ~~to cash provided by financing activities of approximately $19.9~~with $10.0 million during the nine months ended September 30, ~~2014.~~2015. During the nine months ended September 30, 2016, net cash used in financing activities includes the payment of dividends of $71.8 million, the payment of financing costs of $6.6 million, and net repayments of commercial paper of $7.6 million, partially offset by net proceeds from the issuance of debt of $24.5 million. During the nine months ended September 30, 2015, net cash used in financing activities ~~includes the redemption~~consisted of ~~long term debt of $150 million,~~ net repayments of commercial paper of $49.9 million, the payment of dividends of ~~$67.1~~$67.1 million, and the payment of financing costs of $12.1 million, offset in part by net proceeds from the issuance of debt of $270 million. During the nine months ended September 30, 2014, net cash provided by financing activities consisted of proceeds received from the issuance of long term debt of $25.7 million, the issuance of common stock pursuant to our equity distribution agreement of $13.3 million, and net issuances of commercial paper of $29.0 million, offset in part by of the payment of dividends of $46.4$120.0 million.

Financing Transactions - ~~We financed the Beethoven wind project acquisition with a combination of $70~~In June 2016, we issued $60 million aggregate principal amount of South Dakota ~~first mortgage bonds, approximately $57 million of equity and the remainder with short-term borrowings. The $70 million of South Dakota first mortgage bonds were issued in September 2015~~First Mortgage Bonds at a fixed interest rate of ~~4.26%~~2.80% maturing in ~~2040. The~~2026. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018. In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes. These bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended.

In August 2016, the City of Forsyth, Montana, issued on our behalf $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds at a fixed interest rate of 2.00% maturing in 2023. Proceeds from the issuance were loaned to us, and with available funds were used to redeem the City of Forsyth's 4.65%, $170.2 million Pollution Control Revenue Bonds due 2023. Our obligations to repay the loan are secured by the issuance of a series of our First Mortgage Bonds, which, in turn, are secured by our electric and natural gas assets in Montana and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. ~~The equity transaction was completed in October 2015 through the issuance of 1,100,000 shares of our common stock at $51.81 per share.~~

In June 2015, we issued $200 million aggregate principal amount of Montana First Mortgage Bonds, which includes $75 million at a fixed interest rate of 3.11% maturing in 2025 and $125 million at a fixed interest rate of 4.11% maturing in 2045. The bonds are secured by our electric and natural gas assets in Montana. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.04%, $150 million of Montana First Mortgage Bonds due 2016 and finance incremental Montana capital expenditures.

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 September 30, ~~2015~~2016. See our Annual Report on Form 10-K for the year ended December 31, ~~2014~~2015 for additional discussion.


	Total		2015		2016		2017		2018		2019		Thereafter		Total		2016		2017		2018		2019		2020		Thereafter
	(in thousands)														(in thousands)
Long-term debt	$	1,782,123	$	—	$	—	$	—	$	55,000	$	250,000	$	1,477,123	$	1,794,519	$	—	$	—	$	—	$	250,000	$	—	$	1,544,519
Capital leases	28,605		443		1,837		1,979		2,133		2,298		19,915		26,801		476		1,979		2,133		2,298		2,476		17,439
Short-term borrowings	217,943		217,943		—		—		—		—		—		222,311		222,311		—		—		—		—		—
Future minimum operating lease payments	4,139		547		1,803		953		214		116		506
Estimated pension and other postretirement obligations (1)	55,971		1,663		13,680		13,626		13,554		13,448		N/A		55,075		906		13,661		13,554		13,489		13,465		N/A
Qualifying facilities liability (2)	972,901		17,607		72,629		74,684		76,782		78,918		652,281		900,421		18,393		74,607		76,703		78,836		80,984		570,898
Supply and capacity contracts (3)	1,205,974		49,612		156,501		119,445		91,693		87,929		700,794		1,734,039		61,300		199,378		150,808		146,993		112,364		1,063,196
Contractual interest payments on debt (4)	1,480,715		29,493		84,599		84,455		82,676		71,820		1,127,672		1,381,518		23,276		80,027		79,850		69,976		62,051		1,066,338
Environmental remediation obligations (1)	7,503		1,403		2,000		1,600		1,700		800		N/A		6,528		928		1,650		1,650		1,500		800		N/A
Total Commitments (5)	$	5,755,874	$	318,711	$	333,049	$	296,742	$	323,752	$	505,329	$	3,978,291	$	6,121,212	$	327,590	$	371,302	$	324,698	$	563,092	$	272,140	$	4,262,390

_________________________


(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 $~~1.0~~0.9 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $~~0.8~~0.7 billion.


(3)	We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 2726 years.


(4)	For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of ~~0.64%~~0.96% 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 ~~Condensed Consolidated~~ 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 September 30, ~~2015~~2016, 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, ~~2014~~2015. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities 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 ~~established a program where we may~~ issue commercial ~~paper; which is~~paper supported by our revolving credit facility. Since commercial paper terms are short-term, we are subject to interest rate risk. As of September 30, ~~2015~~2016, we had approximately $~~217.9~~222.3 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 $2.2 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, 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 ~~our~~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. 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 ~~14,~~13, 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 ~~government~~state and federal regulatory ~~outcomes, including extensive and changing laws~~

~~and regulations that affect~~outcomes. To the extent our ~~industry and~~incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our ~~operations,~~costs, which could ~~have a material adverse effect on~~adversely impact our ~~liquidity and~~ results of ~~operations.~~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.

~~For example,~~In addition to general rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. 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. The rates are established based upon projected market prices or contractual obligations. As these variables change, we adjust our rates through our monthly trackers, which are subject to approval by the applicable regulatory commissions. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we do not recover some of our costs, which could adversely impact our results of operations.

We have received several unfavorable regulatory rulings in Montana, including:

•In 2016, the MPSC disallowed approximately $8.2 million of replacement power costs from an 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.

We appealed the October 2013 decision regarding DGGS outage costs to the Montana District Court, which, in August 2015, upheld the MPSC’s decision. In October 2015, we appealed the District Court’s decision to the Montana Supreme Court, which, in September 2016, upheld the District Court's decision.

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 property taxes. Adjusted rates are typically effective January 1st of each year. The MPSC has identified concerns with the amount of annual increases proposed by the Montana Department of Revenue. Any change in recovery of property taxes could have a material impact on our results of operations.

In addition, the MPSC Order approving the purchase of hydro assets in Montana provided that customers would have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT). We sold any excess system generation, which was primarily due to our temporary ownership of Kerr, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. The cost of our temporary ownership was not included in rate base, and the benefits were provided to customers. In December 2015, we submitted the required hydro compliance filing to remove Kerr from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro generation rate based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of Kerr. A hearing was held in September 2016, and we expect a final order during the fourth quarter of 2016.

In addition, 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 ~~April 2014,~~May 2016, we received an order from the FERC ~~issued an order affirming~~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 ~~in September 2012,~~ regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded ~~we should allocate~~that only a ~~fraction~~portion of ~~the~~these costs ~~we believe, based on facts and the law,~~ should be allocated to FERC jurisdictional customers. We had deferred cumulative 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 ~~request~~petition for ~~rehearing, which remains pending. If unsuccessful on rehearing, we may appeal to a United States~~review with the U.S. Circuit Court of Appeals ~~which could extend into 2016 or beyond.~~for the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We ~~continue to evaluate~~are evaluating options to use DGGS in combination with other generation resources, including our hydro facilities, to ~~ensure~~minimize portfolio costs, which may facilitate cost recovery. The cost recovery ~~and do not believe an impairment loss is probable at this time. Any~~of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. ~~We will continue to evaluate recovery of this asset in the future as facts and circumstances change.~~ If we are not able to ~~ensure~~obtain cost recovery of DGGS we may be required to record an impairment charge, which could have a material adverse effect on our operating results.

During the second quarter of 2015, we reached a settlement agreement with an insurance carrier for the former Montana Power Company for what were primarily generation related environmental remediation costs. As a result of this settlement, we recognized a net recovery of approximately $20.8 million, which is reflected as a reduction to operating expenses in our other segment. The environmental remediation costs were never reflected in customer rates and the litigation expenses have not been treated as utility expenses. In a 2002 order approving NorthWestern’s acquisition of the transmission and distribution assets of the Montana Power Company, the MPSC approved a stipulation in which NorthWestern agreed to release its customers from all environmental liabilities associated with the Montana Power Company’s generation assets. While we believe the recovery we recognized as a reduction to operating expenses is not subject to refund to customers, the MPSC could disagree with us and could ultimately require us to refund all or a portion of the net recovery to customers, which could have a material adverse effect on our operating results.

Our ability to invest in additional generation is impacted by regulatory and public policy. Under the Public Utility Regulatory Policies Act of 1978, electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (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. In addition, the ~~MPSC Order approving~~cost to procure power from these QFs may not be a cost effective resource for customers, or the ~~Hydro Transaction provided that customers would have no financial risk related to our temporary ownership~~type of ~~the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT. We sold any excess system~~ generation ~~during our temporary ownership of the Kerr Project~~resource needed, resulting in ~~the market and provided~~increased supply costs.

revenue credits to our Montana retail customers until the transfer to the CSKT. We believe the benefits of our temporary ownership of the Kerr Project exceeded any costs to customers. We expect to make the required compliance filing during the fourth quarter of 2015 that will remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to 2015 actual amounts for the Hydro Transaction.

We are subject to many FERC rules and orders that regulate our electric and natural gas business and are subject to periodic audits. ~~We received notice from FERC in~~In March 2015, ~~that it is~~FERC began conducting an audit of our ~~Open Access Transmission Tariffs~~open access transmission tariffs and operations in Montana and South Dakota. These audits typically take up to 24 months to complete.

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 ~~the~~ Western ~~Electricity~~Electric 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 $1 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.

ToWe 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 ~~extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would not recover some~~planning and management of our ~~costs, which could adversely~~operations, we must address the effects of legislation within a regulatory framework. Federal and state laws can significantly impact our ~~results of~~ operations, whether it is new or revised statutes directly affecting the electric and ~~liquidity.~~

~~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. The rates are established based upon projected market prices~~industry, or contractual obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would not recover some of our costs, which could adversely impact our results of operations.

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. We have appealed that decision to the Montana district court, which upheld the MPSC’s decision with respect to the remaining portion of our appeal in August 2015. On October 9, 2015, we filed an appeal with the Montana Supreme Court of the District Court's August 2015 decision.other issues such as taxes. In addition, new or revised statutes can also materially affect our ~~2014 electric tracker filing includes market purchases made between July 2013~~operations through impacting existing regulations or requiring new regulations. These changes are ongoing, and ~~January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion~~we cannot predict the future course of ~~these costs~~changes or the ultimate effect that this changing environment will have on us. Changes in laws, and the tracker filing is consistent with the treatment of replacement power during previous Colstrip outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. In July 2014, the Montana Consumer Counsel, Montana Environmental Information Centerresulting regulations and ~~Sierra Club filed a petition to intervene in the consolidated 2013~~tariffs and 2014 tracker dockets to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. We believe the costs associated with the outagehow they are implemented and ~~incremental market purchases were prudently incurred. However, there is a risk that the MPSC~~interpreted, may ~~ultimately disallow all or a portion of these costs, which could~~ have a material adverse effect on our ~~operating results.~~businesses, financial condition, results of operations and cash flows.

~~We currently procure a large portion~~In April 2016, the U.S. Senate passed the Securing America’s Future Energy: Protecting our Infrastructure of ~~our~~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 bill prioritizes PHMSA's completion of outstanding regulations. In addition, PHMSA proposed revisions to safety standards for natural gas ~~supply through contracts with third-party suppliers. In light~~transmission and gathering pipelines. The long-anticipated proposal could impose significant regulatory requirements for additional miles of ~~this reliance on third-party suppliers,~~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 ~~are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might~~will be required to purchase natural gas supply in the market, which may not be on favorable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.

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, 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, securing adequate capital to support the transaction, and regulatory approval. Uncertainties 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, borrowingsmeet. Costs incurred to ~~finance construction~~comply with the proposed regulations may ~~adversely impact our leverage, which could increase our cost of capital.~~

~~Factors contributing to lower hydroelectric generation can increase costs and negatively impact our financial condition and results of operations.~~

With the Hydro Transaction, we now 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. If hydroelectric generation is lower than anticipated, we may need to increase our use of purchased power or decrease the amount of surplus sales. We expect to recover purchased power costs through our electric tracker mechanism. Recovery of increased costs, however, could be ~~subject to risk of disallowance that would negatively impact our results of operations, or may not occur until the subsequent power cost adjustment year, negatively affecting cash flows and liquidity.~~material.

We are subject to extensive and changing environmental laws and regulations and potential environmental liabilities, which could ~~result in significant costs~~have a material adverse effect on our liquidity and ~~additional liabilities.~~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.

National and international actions have been initiated to address global climate change and the contribution of GHG emissions including, most significantly, carbon dioxide. ~~These actions include legislative proposals, executive and EPA actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions.~~ In August 2015, the EPA released ~~for publication in the Federal Register, the~~ final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed ~~stationary combustion turbines.~~natural gas combined cycle units. In a separate action that also affects power plants, in August 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) (the Clean Power Plan or CPP).

BBER to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility in southeast Montana as a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Colstrip Unit 4 represents approximately 25 percent of our customer needs. Closing all four Colstrip units would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing all four Colstrip units would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to and lower electric customer bills.

In addition to the potential impact of CPP to Colstrip Unit 4, we have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the CPP and the various regulations discussed above that have been issued or proposed. States were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us.

On October 23, 2015, the same date the CPP was published in the Federal Register, we along with other utilities, trade groups, coal producers, and labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefing on the merits. On January 26, 2016, 29 states and state agencies asked the U.S. Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we were among the utilities seeking a stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the CPP. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, and on September 27, 2016, the Court held oral argument in the matter. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018.

Requirements to reduce GHG emissions ~~from stationary sources~~ could cause us to incur material costs of compliance and increase our costs of procuring electricity. Although there continues to be changes in legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty ~~whether~~the impact of these risks ~~will have a material impact~~ on our results of operations.

We are evaluating the implications of these rules and technology available to achieve the ~~CO2~~CO₂ emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters nor what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission 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, ~~and/~~or we are not successful in recovering ~~a material portion of~~ remediation costs or costs to comply with the proposed or any future changes in ~~our rates,~~rules or regulations, our results of operations and financial position could be adversely affected.

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.

For example, 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. There is no assurance that we will be able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

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.

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 ~~population growth as well as by economic factors. Our customers may voluntarily reduce their~~a number of factors, including the voluntary reduction of consumption of electricity and natural gas ~~from us~~by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, ~~individual energy conservation efforts or~~ 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 puts 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, transmission availability and the availability of generation, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

~~Our electric and natural gas 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, 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 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.

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.

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.

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. ~~Changes in precipitation resulting in droughts or water shortages could affect~~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 ~~for hydro generation and adversely~~can significantly affect ~~our ability to provide electricity to customers, as well as increase the price they pay for energy.~~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.

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.

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.

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.

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 discussed above, the proposed consent decree relating to the Colstrip litigation call for Units 1 and 2 to be shut down by July 2022. When Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. In addition, in May 2016, Talen provided a two-year notice of its intent to resign as the operator of Colstrip. We and the other owners are working to select a new operator, which we expect will increase operating costs. At this time we do not anticipate these increases will be material to our results of operations and cash flows. However, the ultimate shutdown of Talen's share of Colstrip Units 1 and 2 will have a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines.

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

Our 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.

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.

Threats of terrorism and catastrophic events that could result from terrorism, cyber attacks, 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 attacks (such as hacking and viruses) and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or indirectly affected by, such activities. Any significant interruption of these systems could prevent us from fulfilling our critical business functions, and sensitive, confidential and other data could be compromised.

Terrorist acts, cyber attacks or other similar events 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.

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit ~~1.1—Underwriting Agreement,~~4.1— Indenture, dated ~~September 29, 2015,~~as of August 1, 2016, between ~~NorthWestern Corporation~~ City of Forsyth, Rosebud County, Montana

and ~~RBC Capital Markets, LLC,~~U.S. Bank National Association, as ~~representative of the Underwriters named therein~~trustee agent (incorporated by reference to Exhibit ~~1.1~~4.1 of NorthWestern ~~Corporation’s~~Corporation's Current Report on Form 8-K, dated ~~September 29, 2015,~~August 16, 2016, Commission File No. 1-10499).

Exhibit ~~2.1—Purchase and Sale~~4.2— Loan Agreement, dated ~~July 22, 2015,~~as of August 1, 2016, between NorthWestern Corporation and ~~BayWa r.e. Wind LLC~~the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit ~~2.1~~4.2 of ~~NorthWestern Corporation’s Current~~the Company's Report on Form 8-K, dated ~~July 22, 2015,~~August 16, 2016, Commission File No. 1-10499).

Exhibit ~~4.1—Thirteenth~~4.3— Bond Delivery Agreement, dated as of August 1, 2016, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).

Exhibit 4.4— Thirty-sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).

Exhibit 4.5— Fifteenth Supplemental Indenture, dated as of September 1, ~~2015,~~2016, among NorthWestern Corporation and The Bank of New York Mellon, as ~~trustees~~trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated ~~September 29, 2015,~~October 6, 2016, Commission File No. 1-10499).

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

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:	October ~~22, 2015~~20, 2016	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer



EXHIBIT INDEX



Exhibit Number		Description
~~1.1~~4.1		~~Underwriting Agreement,~~ Indenture, dated ~~September 29, 2015,~~as of August 1, 2016, between ~~NorthWestern Corporation~~City of Forsyth, Rosebud County, Montana and ~~RBC Capital Markets, LLC,~~U.S. Bank National Association, as ~~representative of the Underwriters named therein~~trustee agent (incorporated by reference to Exhibit ~~1.1~~4.1 of NorthWestern ~~Corporation’s~~Corporation's Current Report on Form 8-K, dated ~~September 29, 2015,~~August 16, 2016, Commission File No. 1-10499).
4.2		Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
~~2.1~~4.3		~~Purchase and Sale~~Bond Delivery Agreement, dated ~~July 22, 2015,~~as of August 1, 2016, between NorthWestern Corporation and ~~BayWa r.e. Wind LLC~~U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit ~~2.1~~4.3 of NorthWestern ~~Corporation’s~~Corporation's Current Report on Form 8-K, dated ~~July 22, 2015,~~August 16, 2016, Commission File No. 1-10499).
~~4.1~~4.4		~~Thirteenth~~Thirty-sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.5		Fifteenth Supplemental Indenture, dated as of September 1, ~~2015,~~2016, among NorthWestern Corporation and The Bank of New York Mellon, as ~~trustees~~trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated ~~September 29, 2015,~~October 6, 2016, Commission File No. 1-10499).
*31.1		Certification of chief executive officer.
*31.2		Certification of chief financial officer.
*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

5870



Purchase Price Allocation	(in millions)
Assets Acquired
Property Plant and Equipment	$	143.0
Other Prepayments	0.1
Total Assets Acquired	$	143.1

Liabilities Assumed
Other Current Liabilities	$	0.3
Total Liabilities Assumed	$	0.3
Total Purchase Price	$	142.8



	Gross Margin 2015 vs. 2014
	(in millions)
Hydro operations	$	40.4
South Dakota electric interim rate increase (subject to refund)	1.8
Property tax tracker	1.3
Electric retail volumes	1.1
Electric transmission capacity	(0.9		)
Natural gas retail volumes	(0.5		)
Gas production deferral	(0.4		)
Other	(1.0		)
Increase in Consolidated Gross Margin	$	41.8



	Gross Margin 2015 vs. 2014
	(in millions)
Operating expenses recovered in trackers	$	(0.6	)
Retail volumes	(0.5		)
Gas production deferral	(0.4		)
Other	(1.3		)
Decrease in Gross Margin	$	(2.8	)

Location of amount reclassified from AOCL to Income

Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016

Interest rate contracts

Interest Expense