NORTHWESTERN CORP - FORM 10-Q

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EX-31.2 - EXHIBIT 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER - NORTHWESTERN CORP	ex312certificationq32015.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - NORTHWESTERN CORP	ex311certificationq32015.htm
EX-32.2 - EXHIBIT 32.2 CERTIFICATION OF BRIAN B. BIRD PURSUANT TO SECTION 906 - NORTHWESTERN CORP	ex322certificationq32015.htm
EX-32.1 - EXHIBIT 32.1 CERTIFICATION OF ROBERT C. ROWE PURSUANT TO SECTION 906 - NORTHWESTERN CORP	ex321certificationq32015.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2015

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 shares outstanding at October 16, 2015

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 and 2014	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2015 and 2014	5
	Condensed Consolidated Balance Sheets — September 30, 2015 and December 31, 2014	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2015 and 2014	7
	Condensed Consolidated Statements of Shareholders' Equity — Nine Months Ended September 30, 2015 and 2014	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50
PART II. OTHER INFORMATION		51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 6.	Exhibits	56
SIGNATURES		57

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.

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,
	2015			2014			2015			2014
Revenues
Electric	$	238,513		$	212,430		$	695,921		$	652,951
Gas	34,226			39,482			193,389			238,965
Total Revenues	272,739			251,912			889,310			891,916
Operating Expenses
Cost of sales	73,577			94,592			265,495			374,494
Operating, general and administrative	79,296			68,108			222,139			214,557
Property and other taxes	35,712			27,773			100,953			84,292
Depreciation and depletion	35,693			30,452			107,239			91,139
Total Operating Expenses	224,278			220,925			695,826			764,482
Operating Income	48,461			30,987			193,484			127,434
Interest Expense, net	(22,043		)	(18,794		)	(68,101		)	(57,887		)
Other Income (Expense)	3,769			(439		)	5,429			4,730
Income Before Income Taxes	30,187			11,754			130,812			74,277
Income Tax (Expense) Benefit	(6,389		)	18,437			(24,616		)	9,240
Net Income	$	23,798		$	30,191		$	106,196		$	83,517
Average Common Shares Outstanding	47,065			39,141			47,029			39,046
Basic Earnings per Average Common Share	$	0.51		$	0.77		$	2.26		$	2.14
Diluted Earnings per Average Common Share	$	0.51		$	0.77		$	2.25		$	2.13
Dividends Declared per Common Share	$	0.48		$	0.40		$	1.44		$	1.20

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net Income	$	23,798		$	30,191		$	106,196		$	83,517
Other comprehensive income (loss), net of tax:
Foreign currency translation	233			134			445			155
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		)
Total Other Comprehensive Loss	(322		)	(1,060		)	(290		)	(1,405		)
Comprehensive Income	$	23,476		$	29,131		$	105,906		$	82,112

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

ASSETS
Current Assets:
Cash and cash equivalents	$	10,135		$	20,362
Restricted cash	18,639			29,662
Accounts receivable, net	117,454			163,479
Inventories	58,692			55,094
Regulatory assets	38,389			47,374
Deferred income taxes	62,370			20,843
Other	10,157			14,071
Total current assets	315,836			350,885
Property, plant, and equipment, net	4,004,516			3,758,008
Goodwill	355,128			355,128
Regulatory assets	502,201			455,757
Other noncurrent assets	57,397			54,165
Total assets	$	5,235,078		$	4,973,943
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,803		$	1,730
Short-term borrowings	217,943			267,840
Accounts payable	60,235			81,961
Accrued expenses	226,024			206,882
Regulatory liabilities	68,908			56,169
Total current liabilities	574,913			614,582
Long-term capital leases	26,802			28,162
Long-term debt	1,782,123			1,662,099
Deferred income taxes	550,234			446,600
Noncurrent regulatory liabilities	374,460			362,228
Other noncurrent liabilities	407,700			382,489
Total liabilities	3,716,232			3,496,160
Commitments and Contingencies (Note 14)
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
Treasury stock at cost	(94,031		)	(92,558		)
Paid-in capital	1,317,617			1,313,844
Retained earnings	303,809			264,758
Accumulated other comprehensive loss	(9,056		)	(8,766		)
Total shareholders' equity	1,518,846			1,477,783
Total liabilities and shareholders' equity	$	5,235,078		$	4,973,943

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



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

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

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

Balance at December 31, 2014	50,522	3,607	$	505	$	1,313,844	$	(92,558	)	$	264,758		$	(8,766	)	$	1,477,783

Net income	—	—	—		—		—			106,196			—			106,196
Foreign currency translation adjustment	—	—	—		—		—			—			445			445
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	—	—	—		—		—			—			(735		)	(735		)
Stock-based compensation	166	—	—		3,304		(1,926		)	—			—			1,378
Issuance of shares	—	13	2		469		453			—			—			924
Dividends on common stock ($1.44 per share)	—	—	—		—		—			(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

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 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, 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.

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 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In April 2015, 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, the FASB issued guidance which eliminates from GAAP the concept of an extraordinary item. 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. The new guidance will be effective for us in our first quarter of 2016 and early adoption is permitted. We do not expect the adoption of this standard to have a material effect on our reporting and disclosure.

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2015 that are of significance, or potential significance, to us.

(3) Acquisitions

Hydro Transaction

In November 2014, we completed the purchase of 11 hydroelectric generating facilities and associated 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 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 the cost of supplying electricity to our customers. We expect to finalize the purchase price allocation, including analysis of environmental matters and potential removal obligations, during the fourth quarter of 2015.

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 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.

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 an annual increase to electric rates totaling approximately $26.5 million. Our request was based on an overall rate of return of 7.67% and rate base of $447.4 million.

In September 2015, we reached a settlement 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, the settlement would allow us to collect approximately $9 million annually related to the Beethoven wind project as discussed above. The settlement is subject to approval of the SDPUC, and a hearing is scheduled for October 2015. The SDPUC is expected to make a final determination in the case by the end of 2015.

We have been collecting interim rates since July 1, 2015, based 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, we filed our annual electric and natural gas supply tracker filings for the 2014/2015 tracker period and received orders from 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 - Our 2013/2014 electric tracker filing included market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous 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. The Montana Consumer Counsel, Montana Environmental Information Center and Sierra Club have intervened in the consolidated docket 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 a final order in the natural gas consolidated 2013/2014 and 2012/2013 tracker docket. This consolidated docket included our request to continue collecting the cost of service for natural gas production interests acquired 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 consistent with the final order.

Electric and Natural Gas Lost Revenue Adjustment Mechanism - Demand-side management (DSM) lowers our sales 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.

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 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 prospectively effective December 1, 2015.

Based on the October 2013 MPSC order, 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. 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 than we have deferred or approve recovery of more DSM lost revenues than we have recognized since July 2012.

Dave Gates Generating Station at Mill Creek (DGGS)

In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if 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 FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal would likely extend into 2016 or beyond.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We are evaluating options to use DGGS in combination with other generation resources, including our newly acquired hydro facilities, to facilitate cost recovery. 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) 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,
	2015					2014
Income Before Income Taxes	$	30,187				$	11,754

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

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

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



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

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

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

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

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.

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 million as of September 30, 2015, including approximately $65.3 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, we did not recognize expense for interest and penalties in the Condensed Consolidated Statements of Income and did not have any amounts accrued at September 30, 2015 and December 31, 2014, respectively, for the payment of interest and penalties.

Our federal tax returns from 2000 forward remain subject to examination by the IRS.

(6) Goodwill

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



Electric	$	241,100
Natural gas	114,028
	$	355,128

(7) Comprehensive Income (Loss)

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



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



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

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



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

The following tables display the changes in AOCI 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
	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
Other comprehensive income before reclassifications		(1,011		)	—			134		(877		)
Amounts reclassified from AOCI	Interest Expense	(183		)	—			—		(183		)
Net current-period other comprehensive (loss) income		(1,194		)	—			134		(1,060		)
Ending balance		$	1,953		$	(1,329	)	$	687	$	1,311



		September 30, 2015
		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		$	(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	)



		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

(8) 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. 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 amounts recorded in the Financial Statements at September 30, 2015 and December 31, 2014. 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. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

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

(9) 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 8 - Risk Management and Hedging Activities for further discussion.

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



	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
September 30, 2015
Restricted cash	$	13,892	$	—	$	—	$	—	$	13,892
Rabbi trust investments	23,760		—		—		—		23,760
Total	$	37,652	$	—	$	—	$	—	$	37,652

December 31, 2014
Restricted cash	$	13,140	$	—	$	—	$	—	$	13,140
Rabbi trust investments	21,594		—		—		—		21,594
Total	$	34,734	$	—	$	—	$	—	$	34,734

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
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,782,123	$	1,862,952	$	1,662,099	$	1,817,642

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) Financing Activities

We financed the Beethoven wind project acquisition with a combination 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 bonds are secured by our electric and natural gas assets in South Dakota 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.

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) 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
Operating revenues	$	238,513		$	34,226		$	—		$	—	$	272,739
Cost of sales	66,197			7,380			—			—		73,577
Gross margin	172,316			26,846			—			—		199,162
Operating, general and administrative	58,298			19,843			1,155			—		79,296
Property and other taxes	28,648			7,062			2			—		35,712
Depreciation and depletion	28,476			7,209			8			—		35,693
Operating income (loss)	56,894			(7,268		)	(1,165		)	—		48,461
Interest expense	(19,078		)	(2,562		)	(403		)	—		(22,043		)
Other income	1,832			507			1,430			—		3,769
Income tax (expense) benefit	(6,553		)	1,883			(1,719		)	—		(6,389		)
Net income (loss)	$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798
Total assets	$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078
Capital expenditures	$	57,813		$	14,341		$	—		$	—	$	72,154



Three Months Ended
September 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	212,430		$	39,482		$	—		$	—	$	251,912
Cost of sales	84,720			9,872			—			—		94,592
Gross margin	127,710			29,610			—			—		157,320
Operating, general and administrative	48,528			21,005			(1,425		)	—		68,108
Property and other taxes	20,413			7,357			3			—		27,773
Depreciation and depletion	23,174			7,270			8			—		30,452
Operating income (loss)	35,595			(6,022		)	1,414			—		30,987
Interest expense	(14,025		)	(2,627		)	(2,142		)	—		(18,794		)
Other income (expense)	1,337			336			(2,112		)	—		(439		)
Income tax benefit	5,235			926			12,276			—		18,437
Net income (loss)	$	28,142		$	(7,387	)	$	9,436		$	—	$	30,191
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	62,054		$	12,011		$	—		$	—	$	74,065



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
Operating revenues	$	652,951		$	238,965		$	—		$	—	$	891,916
Cost of sales	273,754			100,740			—			—		374,494
Gross margin	379,197			138,225			—			—		517,422
Operating, general and administrative	144,933			66,254			3,370			—		214,557
Property and other taxes	61,322			22,961			9			—		84,292
Depreciation and depletion	69,398			21,716			25			—		91,139
Operating income (loss)	103,544			27,294			(3,404		)	—		127,434
Interest expense	(43,663		)	(7,979		)	(6,245		)	—		(57,887		)
Other income	3,204			876			650			—		4,730
Income tax (expense) benefit	(575		)	(3,334		)	13,149			—		9,240
Net income	$	62,510		$	16,857		$	4,150		$	—	$	83,517
Total assets	$	2,694,883		$	1,170,843		$	8,572		$	—	$	3,874,298
Capital expenditures	$	161,718		$	24,367		$	—		$	—	$	186,085

(12) 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
	September 30, 2015	September 30, 2014
Basic computation	47,065,082	39,141,148
Dilutive effect of
Performance share awards (1)	245,463	139,655

Diluted computation	47,310,545	39,280,803



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

Diluted computation	47,274,384	39,187,350

______________

(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) 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,
	2015			2014			2015			2014
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,091		$	2,708		$	132		$	116
Interest cost	6,544			6,536			197			214
Expected return on plan assets	(7,890		)	(7,377		)	(242		)	(245		)
Amortization of prior service cost	62			62			(471		)	(500		)
Recognized actuarial loss	2,659			530			96			87
Net Periodic Benefit Cost (Income)	$	4,466		$	2,459		$	(288	)	$	(328	)



	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) 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 million to $35.0 million. As of September 30, 2015, we have a reserve of approximately $28.3 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 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 reserve for remediation costs at this site is approximately $10.4 million, and we estimate that approximately $7.5 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 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. 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, a draft risk assessment was prepared for the Missoula site and presented to the Missoula County Water Quality Board (MCWQB). The MCWQB deferred all decision making 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 of 2015. 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.

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. 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 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. 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 Clean Power Plan or CPP. The CPP specifically establishes CO2 emission performance standards for existing electric utility steam generating units and stationary combustion turbines. 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. The 2030 rate-based requirement for all existing affected generating units in Montana and South Dakota is 1,305 and 1,167 pounds per MWH, respectively. The mass-based approach for existing affected generating units calls for a 37 percent reduction from 2012 levels by 2030 in Montana. The mass-based approach for existing units in South Dakota permits an 11 percent increase by 2030. States are required to submit initial plans for achieving GHG emission standards to EPA by September 2016, but may seek additional time to finalize State plans by September 2018. The initial performance period for compliance 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 would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program, which would allow trading of allowances with an allowance equal to one short ton of CO2; and a state measures program, that would allow intra-state trading to achieve the state-wide average emission rate.

On August 3, 2015, 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 on the proposed federal plan and model trading rule will be due ninety days after it is published in the Federal Register.

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 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.

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 Court of Appeals.

On September 30, 2015, the EPA issued final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. 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 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 without vacatur of the MATS rule, and in support of that request, the EPA will submit to the court a declaration establishing a plan to "complete the required consideration of costs" to support the "appropriate and necessary finding" by spring 2016. Installation or upgrading of relevant environmental controls at our affected plants is complete or they have received compliance extensions, as applicable. At this time, we cannot predict whether and when compliance with the MATS rule ultimately will be required.

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) 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. Litigation of the remaining CSAPR lawsuits continues, with a decision expected by the end of 2015.

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 that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana, the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center, 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 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. The South Dakota DENR determined that the Big Stone plant, in which we have a 23.4% ownership, is subject to the BART requirements 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 SO₂, 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. The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx emissions. Coyote must install control equipment to limit its NOx emissions to 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. 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 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.

Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's CCR 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 million (our share is 30.0%) 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 Colstrip, including us, as well as the operator or managing agent of the station (Defendants). 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 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, 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, 2013, the Colstrip owners and operator filed a partial motion 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.

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 Magistrate issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motion 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 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 filing the Second Amended Complaint, Plaintiffs have indicated that they are no longer pursuing a number of claims and projects thereby reducing their total claims to eight relating to four projects. The parties have filed motions for summary judgment with regard to issues affecting the remaining claims, and the motions for summary judgment are fully briefed. Oral argument on all pending motions for summary judgment is scheduled for December 1, 2015, and a bench trial is scheduled for May 31, 2016.

We intend to vigorously defend this lawsuit. At this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision.

Billings Refinery Outage Claim

In August 2014, we received a demand letter from a refinery in Billings claiming that it had sustained damages of approximately $48.5 million as a result of a January 2014 electrical outage. We dispute the claim and intend to vigorously defend against it. We reported the refinery's claim to our insurance carrier under our primary insurance policy, which has a $2.0 million retention. 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.

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 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.

Significant items during the three months ended September 30, 2015 include:

•

Completed the purchase of the 80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments). We financed the Beethoven wind project acquisition with a combination 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

Net income for the three months ended September 30, 2015 was $23.8 million, or $0.51 per diluted share, as compared with net income of $30.2 million, or $0.77 per diluted share, for the same period in 2014. This decrease was primarily due to an income tax benefit of $16.9 million included in our 2014 results due to the release of previously unrecognized tax benefits, partly offset by the favorable impacts of our Hydro Transaction.

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 Compared with the Three Months Ended September 30, 2014



	Three Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	238.5	$	212.4	$	26.1		12.3	%
Natural Gas	34.2		39.5		(5.3		)	(13.4	)
	$	272.7	$	251.9	$	20.8		8.3	%



	Three Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	66.2	$	84.7	$	(18.5	)	(21.8	)%
Natural Gas	7.4		9.9		(2.5		)	(25.3	)
	$	73.6	$	94.6	$	(21.0	)	(22.2	)%



	Three Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	172.3	$	127.7	$	44.6		34.9	%
Natural Gas	26.8		29.6		(2.8		)	(9.5	)
	$	199.1	$	157.3	$	41.8		26.6	%

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

Consolidated gross margin increased $41.8 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; and


•	An increase in electric retail volumes due primarily to customer growth in the residential and commercial categories and warmer summer weather in South Dakota.

These increases were partly offset by:


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


•	A decrease in natural gas residential and commercial retail volumes; and


•	A deferral of interim gas production revenue based on actual costs in accordance with the final order in the natural gas consolidated 2013/2014 and 2012/2013 tracker docket received in October 2015.



	Three Months Ended September 30,
	2015		2014		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	79.3	$	68.1	$	11.2	16.4	%
Property and other taxes	35.7		27.8		7.9		28.4
Depreciation and depletion	35.7		30.5		5.2		17.0
	$	150.7	$	126.4	$	24.3	19.2	%

Consolidated operating, general and administrative expenses were $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. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2015 vs. 2014
	(in millions)
Hydro operations	$	10.8
Non-employee directors deferred compensation	3.5
Hydro Transaction costs	(0.6		)
Bad debt expense	(0.5		)
Other	(2.0		)
Increase in Operating, General & Administrative Expenses	$	11.2

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


•	Hydro operating costs associated with the November 2014 Hydro Transaction; and

•

Non-employee directors deferred compensation increased as compared to the prior year, primarily due to an increase 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 in other income with no impact on net income.

These increases were partly offset by the following:


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


•	Lower bad debt expense, due to improved collection of receivables from customers.

Property and other taxes were $35.7 million for the three months ended September 30, 2015, as compared with $27.8 million in the same period of 2014. This increase was primarily due to plant additions and higher estimated property valuations in Montana, which includes an estimated $6.4 million from the Hydro Transaction. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.

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

Consolidated operating income for the three months ended September 30, 2015 was $48.5 million, as compared with $31.0 million in the same period of 2014. This increase was primarily due to the impacts of our Hydro Transaction.

Consolidated interest expense for the three months ended September 30, 2015 was $22.0 million, as compared with $18.8 million in the same period of 2014. This increase was primarily due to increased debt outstanding associated with the Hydro Transaction.

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

Consolidated income tax expense for the three months ended September 30, 2015 was $6.4 million, as compared with an income tax benefit of $18.4 million in the same period of 2014. Our effective tax rate for the three months ended September 30, 2015 was 21.2% as compared with (156.9)% 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. We currently expect our 2015 effective tax rate to range between 17% - 19%.



	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 was $23.8 million as compared with $30.2 million for the same period in 2014. This decrease was primarily due to an income tax benefit included in our 2014 results due to the release of previously unrecognized tax benefits, partly offset by the favorable impacts of our Hydro Transaction.

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



	Nine Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	695.9	$	653.0	$	42.9		6.6	%
Natural Gas	193.4		239.0		(45.6		)	(19.1	)
	$	889.3	$	892.0	$	(2.7	)	(0.3	)%



	Nine Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	196.0	$	273.8	$	(77.8	)	(28.4	)%
Natural Gas	69.5		100.7		(31.2		)	(31.0	)
	$	265.5	$	374.5	$	(109.0	)	(29.1	)%



	Nine Months Ended September 30,
	2015		2014		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	499.9	$	379.2	$	120.7		31.8	%
Natural Gas	123.9		138.3		(14.4		)	(10.4	)
	$	623.8	$	517.5	$	106.3		20.5	%

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

Consolidated gross margin increased $106.3 million primarily due to 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 on an interim basis in July 2015.

These increases were partly offset by:


•	A decrease in electric and natural gas retail volumes due primarily to the seasonal impacts of milder weather, partly offset by customer growth;


•	A $6.1 million 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 in trackers, primarily related to customer efficiency programs.



	Nine Months Ended September 30,
	2015		2014		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	222.1	$	214.6	$	7.5	3.5	%
Property and other taxes	101.0		84.3		16.7		19.8
Depreciation and depletion	107.2		91.1		16.1		17.7
	$	430.3	$	390.0	$	40.3	10.3	%

Consolidated operating, general and administrative expenses were $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. 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

The increase in operating, general and administrative expenses of $7.5 million was 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 insurance recovery primarily associated with electric generation related environmental remediation costs incurred in prior periods;


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


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


•	Non-employee directors deferred compensation decreased as compared to the prior year, primarily due to a decrease in our stock price during the nine months ended September 30, 2015; and


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

implemented by customers.

Property and other taxes were $101.0 million for the nine months ended September 30, 2015, as compared with $84.3 million in the same period of 2014. This increase was primarily due to plant additions and higher estimated property valuations in Montana, which includes an estimated $13.8 million from the Hydro Transaction.

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

Consolidated operating income for the nine months ended September 30, 2015 was $193.5 million, as compared with $127.4 million in the same period of 2014. This increase was primarily due to the Hydro Transaction and insurance recovery discussed above.

Consolidated interest expense for the nine months ended September 30, 2015 was $68.1 million, as compared with $57.9 million in the same period of 2014. This increase was primarily due to increased debt outstanding associated with the Hydro Transaction.

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

Consolidated income tax expense for the nine months ended September 30, 2015 was $24.6 million, as compared with an income tax benefit of $9.2 million in the same period of 2014. This increase was due to higher pre-tax income and an increase in our effective tax rate to 18.8% for the nine months ended September 30, 2015 as compared with (12.4)% for the nine months ended September 30, 2014. The income tax benefit in 2014 was primarily a result 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,
	2015					2014
Income Before Income Taxes	$	130.8				$	74.3

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

Permanent or flow through adjustments:
State income, net of federal provisions	(0.3		)	(0.3	)	0.3			0.3
Flow-through repairs deductions	(17.2		)	(13.2	)	(14.9		)	(20.0	)
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	)
Plant and depreciation of flow through items	(1.0		)	(0.8	)	(0.2		)	(0.2	)
Other, net	(1.1		)	(0.7	)	(0.5		)	(0.7	)
	(21.2		)	(16.2	)	(35.2		)	(47.4	)

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

Consolidated net income for the nine months ended September 30, 2015 was $106.2 million as compared with $83.5 million for the same period in 2014. This increase was primarily due to the Hydro Transaction and insurance recovery as discussed above, partly offset by an income tax benefit included in our 2014 results due to the release of previously unrecognized tax benefits.

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 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 electric revenues.

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



	Results
	2015		2014			Change			% Change
	(dollars in millions)
Retail revenues	$	208.2	$	197.9		$	10.3		5.2	%
Regulatory amortization	12.5		(2.3		)	14.8			643.5
Total retail revenues	220.7		195.6			25.1			12.8
Transmission	13.8		14.7			(0.9		)	(6.1	)
Regulation services	0.4		0.3			0.1			33.3
Other	3.6		1.8			1.8			100.0
Total Revenues	238.5		212.4			26.1			12.3
Total Cost of Sales	66.2		84.7			(18.5		)	(21.8	)
Gross Margin	$	172.3	$	127.7		$	44.6		34.9	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Electric
Montana	$	65,296	$	59,545	559	545	287,708	283,412
South Dakota	13,376		12,527		142	132	49,811	49,581
Residential	78,672		72,072		701	677	337,519	332,993
Montana	86,942		84,726		827	826	64,873	63,906
South Dakota	20,679		19,963		259	251	12,571	12,451
Commercial	107,621		104,689		1,086	1,077	77,444	76,357
Industrial	10,420		10,329		558	559	75	77
Other	11,455		10,805		91	86	7,952	8,031
Total Retail Electric	$	208,168	$	197,895	2,436	2,399	422,990	417,458



	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	2015	2014	Historic Average	2014	Historic Average
Montana	340	330	342	3% cooler	1% warmer
South Dakota	73	107	83	32% warmer	12% warmer

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



	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

This increase in gross margin was primarily due to 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;


•	An increase in property taxes included in trackers;


•	An increase in electric retail volumes due primarily to 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 demand to transmit energy across our transmission lines due to market pricing and other conditions.

Billed revenues cover the costs of operating utility assets, paying taxes and interest, and earning a return on our shareholders’ investments. As a result of the Hydro Transaction, we also earn a return on these assets, thereby increasing revenue.

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 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.

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



	Results
	2015		2014		Change			% Change
	(dollars in millions)
Retail revenues	$	621.9	$	583.7	$	38.2		6.5	%
Regulatory amortization	23.1		21.6		1.5			6.9
Total retail revenues	645.0		605.3		39.7			6.6
Transmission	41.1		40.8		0.3			0.7
Regulation services	1.2		1.2		—			—
Other	8.6		5.7		2.9			50.9
Total Revenues	695.9		653.0		42.9			6.6
Total Cost of Sales	196.0		273.8		(77.8		)	(28.4	)
Gross Margin	$	499.9	$	379.2	$	120.7		31.8	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Electric
Montana	$	206,284	$	192,303	1,732	1,773	286,854	282,836
South Dakota	38,031		39,049		434	453	49,774	49,548
Residential	244,315		231,352		2,166	2,226	336,628	332,384
Montana	262,367		242,274		2,401	2,410	64,594	63,658
South Dakota	56,552		56,343		739	738	12,467	12,322
Commercial	318,919		298,617		3,140	3,148	77,061	75,980
Industrial	33,412		30,612		1,697	1,642	75	75
Other	25,250		23,154		167	156	6,252	6,260
Total Retail Electric	$	621,896	$	583,735	7,170	7,172	420,016	414,699



	Degree Days			2015 as compared with:
Cooling Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	382	332	314	15% warmer	22% warmer
South Dakota	719	544	699	32% warmer	3% warmer



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	4,328	5,049	4,937	14% warmer	12% warmer
South Dakota	5,342	6,265	5,612	15% warmer	5% warmer

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



	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

This increase in gross margin was primarily due to 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 rates implemented on an interim basis in July 2015.

These increases were partly offset by:


•	A $6.1 million 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; and


•	A decrease in retail volumes due primarily to warmer winter weather partly offset by warmer spring weather, customer growth and warmer summer weather in South Dakota as compared with the same period of 2014.

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 Compared with the Three Months Ended September 30, 2014



	Results
	2015		2014		Change			% Change
	(dollars in millions)
Retail revenues	$	20.7	$	25.4	$	(4.7	)	(18.5	)%
Regulatory amortization	4.0		4.0		—			—
Total retail revenues	24.7		29.4		(4.7		)	(16.0	)
Wholesale and other	9.5		10.1		(0.6		)	(5.9	)
Total Revenues	34.2		39.5		(5.3		)	(13.4	)
Total Cost of Sales	7.4		9.9		(2.5		)	(25.3	)
Gross Margin	$	26.8	$	29.6	$	(2.8	)	(9.5	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Gas
Montana	$	9,227	$	11,057	832	904	165,829	163,474
South Dakota	1,770		2,051		113	116	38,523	38,196
Nebraska	1,886		2,299		148	154	36,662	36,480
Residential	12,883		15,407		1,093	1,174	241,014	238,150
Montana	5,219		6,567		579	596	22,810	22,580
South Dakota	1,397		1,726		228	210	6,225	6,105
Nebraska	1,026		1,457		174	194	4,599	4,571
Commercial	7,642		9,750		981	1,000	33,634	33,256
Industrial	130		135		17	13	262	260
Other	66		102		9	10	153	153
Total Retail Gas	$	20,721	$	25,394	2,100	2,197	275,063	271,819



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	340	330	342	3% cooler	1% warmer
South Dakota	73	107	83	32% warmer	12% warmer
Nebraska	27	63	44	57% warmer	39% warmer

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



	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	)

This decrease in gross margin was primarily due to lower revenue for operating expenses recovered through our supply trackers, primarily related to efficiency measures implemented by customers, a decrease in residential 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 in 2015 resulting in lower retail revenues and cost of sales as compared with 2014, with no impact to gross margin.

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



	Results
	2015		2014		Change			% Change
	(dollars in millions)
Retail revenues	$	159.3	$	202.7	$	(43.4	)	(21.4	)%
Regulatory amortization	3.4		3.7		(0.3		)	8.1
Total retail revenues	162.7		206.4		(43.7		)	(21.2	)
Wholesale and other	30.7		32.6		(1.9		)	(5.8	)
Total Revenues	193.4		239.0		(45.6		)	(19.1	)
Total Cost of Sales	69.5		100.7		(31.2		)	(31.0	)
Gross Margin	$	123.9	$	138.3	$	(14.4	)	(10.4	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Gas
Montana	$	64,724	$	86,186	7,420	8,460	165,801	163,662
South Dakota	19,944		22,820		2,151	2,553	38,770	38,490
Nebraska	16,964		19,528		1,851	2,116	36,894	36,787
Residential	101,632		128,534		11,422	13,129	241,465	238,939
Montana	33,140		44,869		4,003	4,840	22,924	22,707
South Dakota	13,529		16,670		2,096	2,322	6,268	6,138
Nebraska	9,564		10,862		1,414	1,580	4,639	4,619
Commercial	56,233		72,401		7,513	8,742	33,831	33,464
Industrial	855		920		109	96	263	262
Other	621		856		89	104	152	153
Total Retail Gas	$	159,341	$	202,711	19,133	22,071	275,711	272,818



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	4,328	5,049	4,937	14% warmer	12% warmer
South Dakota	5,342	6,265	5,612	15% warmer	5% warmer
Nebraska	4,382	4,775	4,614	8% warmer	5% warmer

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



	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	)

This decrease in gross margin and volumes was primarily due to the same reasons discussed in the three months ended section above, with a decrease in retail volumes from warmer winter and spring weather. In addition, average natural gas supply prices decreased in 2015 resulting in lower retail revenues and cost of sales as compared with 2014, with no impact to gross margin. The decrease 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.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Funds

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

We issue debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities we utilize available cash flow, debt capacity and equity issuances that allow us to maintain investment grade ratings. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding capital leases, and expect to continue 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, our total net liquidity was approximately $142.2 million, including $10.1 million of cash and $132.1 million of revolving credit facility availability. Revolving credit facility availability was $196.1 million as of October 16, 2015. We financed the Beethoven wind project acquisition with a combination 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.

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



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

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

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, 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
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,
	2015			2014
Operating Activities
Net income	$	106.2		$	83.5
Non-cash adjustments to net income	132.2			123.0
Changes in working capital	65.1			36.5
Other	0.9			(38.1		)
	304.4			204.9

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

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

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

Cash Provided by Operating Activities

As of September 30, 2015, cash and cash equivalents were $10.1 million as compared with $20.4 million at December 31, 2014 and $17.7 million at September 30, 2014. Cash provided by operating activities totaled $304.4 million for the nine months ended September 30, 2015 as compared with $204.9 million during the nine months ended September 30, 2014. This increase in operating cash flows is primarily due to higher net income adjusted for noncash depreciation, primarily due to the results of the Hydro Transaction, and a reduction in our under collection of supply costs in our trackers during the current period that impacted working capital. This increase was offset in part by an $18.4 million settlement of interest rate swaps during the first quarter of 2015.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $81.0 million as compared with the first nine months of 2014. During September 2015, we completed the purchase of the 80 MW Beethoven wind project in South Dakota for approximately $143 million. Plant additions during 2015 include maintenance additions of approximately $139.7 million, supply related capital expenditures of approximately $23.5 million, primarily related to electric generation facilities in South Dakota, and Distribution System Infrastructure Project (DSIP) capital expenditures of approximately $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) Financing Activities

Cash used in financing activities totaled approximately $10.0 million during the nine months ended September 30, 2015 as compared to cash provided by financing activities of approximately $19.9 million during the nine months ended September 30, 2014. During the nine months ended September 30, 2015, net cash used in financing activities includes the redemption of long term debt of $150 million, net repayments of commercial paper of $49.9 million, the payment of dividends of $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 million.

Financing Transactions - We financed the Beethoven wind project acquisition with a combination 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 bonds are secured by our electric and natural gas assets in South Dakota 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. See our Annual Report on Form 10-K for the year ended December 31, 2014 for additional discussion.



	Total		2015		2016		2017		2018		2019		Thereafter
	(in thousands)
Long-term debt	$	1,782,123	$	—	$	—	$	—	$	55,000	$	250,000	$	1,477,123
Capital leases	28,605		443		1,837		1,979		2,133		2,298		19,915
Short-term borrowings	217,943		217,943		—		—		—		—		—
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
Qualifying facilities liability (2)	972,901		17,607		72,629		74,684		76,782		78,918		652,281
Supply and capacity contracts (3)	1,205,974		49,612		156,501		119,445		91,693		87,929		700,794
Contractual interest payments on debt (4)	1,480,715		29,493		84,599		84,455		82,676		71,820		1,127,672
Environmental remediation obligations (1)	7,503		1,403		2,000		1,600		1,700		800		N/A
Total Commitments (5)	$	5,755,874	$	318,711	$	333,049	$	296,742	$	323,752	$	505,329	$	3,978,291

_________________________


(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 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $0.8 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 27 years.


(4)	For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 0.64% 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, 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. 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 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, we had approximately $217.9 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 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, 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 and regulatory outcomes, including extensive and changing laws

and regulations that affect our industry and our operations, which could have a material adverse effect on our liquidity and results of operations.

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 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, the FERC issued an order affirming a 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 only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We filed a request for rehearing, which remains pending. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals, which could extend into 2016 or beyond. 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 options to use DGGS in combination with other generation resources to ensure cost recovery, and do not believe an impairment loss is probable at this time. 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 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.

In addition, the 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 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 March 2015 that it is conducting an audit of our 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 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.

To the extent our incurred 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 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 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. In addition, our 2014 electric tracker filing includes market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in 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 Center and Sierra Club filed a petition to intervene in the consolidated 2013 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 outage and incremental market purchases were prudently incurred. However, there is a risk that the MPSC may ultimately disallow all or a portion of these costs, which could have a material adverse effect on our operating results.

We currently procure a large portion of our natural gas supply through contracts with third-party suppliers. In light of this reliance on third-party suppliers, 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 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, borrowings incurred to finance construction 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.

We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and additional liabilities.

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. 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).

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 these risks will have a material impact on our operations.

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 recovering a material portion of remediation costs in our rates, 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 consumption of electricity and natural gas from us in response to increases in prices, decreases in their disposable income, individual energy conservation efforts or the use of distributed generation for electricity.

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.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding

requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

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

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

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

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.

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 the availability of water for hydro generation and adversely affect our ability to provide electricity to customers, as well as increase the price they pay for energy. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

We 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, dated September 29, 2015, between NorthWestern Corporation and RBC Capital Markets, LLC, as representative of the Underwriters named therein (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, Commission File No. 1-10499).

Exhibit 2.1—Purchase and Sale Agreement, dated July 22, 2015, between NorthWestern Corporation and BayWa r.e. Wind LLC (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated July 22, 2015, Commission File No. 1-10499).

Exhibit 4.1—Thirteenth Supplemental Indenture, dated as of September 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, 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	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		Underwriting Agreement, dated September 29, 2015, between NorthWestern Corporation and RBC Capital Markets, LLC, as representative of the Underwriters named therein (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, Commission File No. 1-10499).
2.1		Purchase and Sale Agreement, dated July 22, 2015, between NorthWestern Corporation and BayWa r.e. Wind LLC (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated July 22, 2015, Commission File No. 1-10499).
4.1		Thirteenth Supplemental Indenture, dated as of September 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, 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

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