NORTHWESTERN CORP - Quarter Report: 2015 June (Form 10-Q)

Location of amount reclassified from AOCI to Income

Amount Reclassified from AOCI into Income during the Six Months Ended June 30, 2015

Interest rate contracts

Interest Expense

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 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

47,063,574 shares outstanding at July 17, 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 Six Months Ended June 30, 2015 and 2014	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2015 and 2014	5
	Condensed Consolidated Balance Sheets — June 30, 2015 and December 31, 2014	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2015 and 2014	7
	Condensed Consolidated Statements of Shareholders' Equity — Six Months Ended June 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	48
Item 4.	Controls and Procedures	49
PART II. OTHER INFORMATION		50
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 6.	Exhibits	55
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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues
Electric	221,362			$	206,010		$	457,408		$	440,521
Gas	49,198			64,271			159,163			199,483
Total Revenues	270,560			270,281			616,571			640,004
Operating Expenses
Cost of sales	79,527			112,474			191,918			279,902
Operating, general and administrative	61,720			74,367			142,843			146,449
Property and other taxes	32,454			27,974			65,241			56,519
Depreciation and depletion	35,727			30,369			71,546			60,687
Total Operating Expenses	209,428			245,184			471,548			543,557
Operating Income	61,132			25,097			145,023			96,447
Interest Expense, net	(22,943		)	(19,127		)	(46,058		)	(39,093		)
Other Income	995			2,980			1,660			5,169
Income Before Income Taxes	39,184			8,950			100,625			62,523
Income Tax Expense	(8,211		)	(1,204		)	(18,227		)	(9,197		)
Net Income	$	30,973		$	7,746		$	82,398		$	53,326
Average Common Shares Outstanding	47,044			39,137			47,011			38,997
Basic Earnings per Average Common Share	0.66			$	0.20		$	1.75		$	1.37
Diluted Earnings per Average Common Share	0.65			$	0.20		$	1.74		$	1.37
Dividends Declared per Common Share	0.48			$	0.40		$	0.96		$	0.80

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 June 30,				Six Months Ended June 30,
	2015		2014		2015			2014
Net Income	30,973		7,746		$	82,398		$	53,326
Other comprehensive income (loss), net of tax:
Reclassification of net gains on derivative instruments	(91	)	(183	)	(180		)	(366		)
Foreign currency translation	(56	)	(82	)	212			21
Total Other Comprehensive (Loss) Income	(147	)	(265	)	32			(345		)
Comprehensive Income	30,826		7,481		$	82,430		$	52,981

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)



	June 30, 2015			December 31, 2014

ASSETS
Current Assets:
Cash and cash equivalents	$	32,868		$	20,362
Restricted cash	20,521			29,662
Accounts receivable, net	122,888			163,479
Inventories	51,062			55,094
Regulatory assets	26,795			47,374
Deferred income taxes	42,920			20,843
Other	15,111			14,071
Total current assets	312,165			350,885
Property, plant, and equipment, net	3,843,234			3,758,008
Goodwill	355,128			355,128
Regulatory assets	494,675			455,757
Other noncurrent assets	54,866			54,165
Total assets	$	5,060,068		$	4,973,943
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,777		$	1,730
Short-term borrowings	219,909			267,840
Accounts payable	52,200			81,961
Accrued expenses	175,578			206,882
Regulatory liabilities	60,558			56,169
Total current liabilities	510,022			614,582
Long-term capital leases	27,278			28,162
Long-term debt	1,712,111			1,662,099
Deferred income taxes	516,479			446,600
Noncurrent regulatory liabilities	369,808			362,228
Other noncurrent liabilities	407,716			382,489
Total liabilities	3,543,414			3,496,160
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 50,685,829 and 47,062,217 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	507			505
Treasury stock at cost	(94,125		)	(92,558		)
Paid-in capital	1,316,610			1,313,844
Retained earnings	302,396			264,758
Accumulated other comprehensive loss	(8,734		)	(8,766		)
Total shareholders' equity	1,516,654			1,477,783
Total liabilities and shareholders' equity	$	5,060,068		$	4,973,943

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Six Months Ended June 30,
	2015			2014
OPERATING ACTIVITIES:
Net income	$	82,398		$	53,326
Items not affecting cash:
Depreciation and depletion	71,546			60,687
Amortization of debt issue costs, discount and deferred hedge gain	562			3,226
Stock-based compensation costs	2,331			1,531
Equity portion of allowance for funds used during construction	(3,971		)	(2,541		)
Gain on disposition of assets	(87		)	(107		)
Deferred income taxes	19,919			32,575
Changes in current assets and liabilities:
Restricted cash	(12		)	(8,664		)
Accounts receivable	40,591			44,571
Inventories	4,032			2,684
Other current assets	(1,040		)	2,630
Accounts payable	(30,186		)	(26,323		)
Accrued expenses	(30,881		)	(13,500		)
Regulatory assets	20,579			(13,139		)
Regulatory liabilities	4,389			5,375
Other noncurrent assets	(1,014		)	(25,237		)
Other noncurrent liabilities	11,182			7,468
Cash provided by operating activities	190,338			124,562
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(131,170		)	(112,020		)
Change in restricted cash	9,153			—
Acquisitions	(492		)	1,455
Proceeds from sale of assets	80			147
Cash used in investing activities	(122,429		)	(110,418		)
FINANCING ACTIVITIES:
Treasury stock activity	(1,008		)	(957		)
Proceeds from issuance of common stock, net	—			13,329
Dividends on common stock	(44,760		)	(30,940		)
Issuance of long-term debt	200,000			—
Repayments on long-term debt	(150,016		)	(57		)
(Repayments) issuances of short-term borrowings, net	(47,931		)	5,002
Financing costs	(11,688		)	(144		)
Cash used in financing activities	(55,403		)	(13,767		)
Increase in Cash and Cash Equivalents	12,506			377
Cash and Cash Equivalents, beginning of period	20,362			16,557
Cash and Cash Equivalents, end of period	$	32,868		$	16,934
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	27		$	20
Interest	44,611			31,756
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	9,199			7,360

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	—	—	$	—	$	—		$	—		$	53,326		$	—		$	53,326
Foreign currency translation adjustment	—	—	$	—	$	—		$	—		$	—		$	21		$	21
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	—	—	$	—	$	—		$	—		$	—		$	(366	)	$	(366	)
Stock-based compensation	116	18	$	—	$	2,065		$	(957	)	$	—		$	—		$	1,108
Issuance of shares	296	—	$	5	$	13,329		$	—		$	—		$	—		$	13,334
Dividends on common stock ($0.80 per share)	—	—	$	—	$	—		$	—		$	(30,940	)	$	—		$	(30,940	)
Balance at June 30, 2014	42,752	3,613	$	428	$	925,578		$	(92,701	)	$	231,477		$	2,371		$	1,067,153

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

Net income	—	—	$	—	$	—		$	—		$	82,398		$	—		$	82,398
Foreign currency translation adjustment	—	—	$	—	$	—		$	—		$	—		$	212		$	212
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	—	—	$	—	$	—		$	—		$	—		$	(180	)	$	(180	)
Stock-based compensation	164	17	$	—	$	2,888		$	(1,567	)	$	—		$	—		$	1,321
Issuance of shares	—	—	$	2	$	(122	)	$	—		$	—		$	—		$	(120	)
Dividends on common stock ($0.96 per share)	—	—	$	—	$	—		$	—		$	(44,760	)	$	—		$	(44,760	)
Balance at June 30, 2015	50,686	3,624	$	507	$	1,316,610		$	(94,125	)	$	302,396		$	(8,734	)	$	1,516,654

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 June 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 $285.9 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 six months ended June 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 2015.

Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 MW hydro-electric generating facility. Upon the close of the Hydro Transaction, we assumed temporary ownership of the Kerr Project. The associated FERC license gives the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) the right to acquire the Kerr Project between September 2015 and September 2025. The CSKT formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Our purchase agreement for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pays $18.3 million for the Kerr Project, Talen Energy (formerly PPL Montana) will pay the difference of $11.7 million to us.

We expect to sell any excess system generation, primarily from the Kerr Project, in the market and provide revenue credits to our Montana retail customers until the Kerr Project is transferred to the CSKT. The MPSC Order approving the Hydro Transaction provides that customers will 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.

South Dakota Wind Generation

In July 2015, we executed an agreement with BayWa r.e. Wind, LLC, to purchase a wind project in Bon Homme, Hutchinson and Charles Mix Counties, South Dakota that would provide approximately 80 MW of capacity, at an estimated aggregate purchase price of approximately $143 million (subject to customary post closing adjustments). The energy and renewable energy credits associated with this project are currently included in our South Dakota electric supply portfolio under a power purchase agreement. We expect to close on the transaction during the second half of 2015, which would terminate the existing power purchase agreement and plan to seek approval to include the wind project in rate base as a part of our pending South Dakota electric rate filing as a known and measurable adjustment.

We have not completed the accounting for the business combination and have not made certain disclosures. The initial accounting and related disclosures for business combinations will be made in subsequent financial statements.

(4) Regulatory Matters

South Dakota Electric Rate Filing

In December 2014, we filed a request with the SDPUC for an annual increase to electric rates totaling approximately $26.5 million. Our request was based on a return on equity of 10%, a capital structure consisting of 46% debt and 54% equity and rate base of $447.4 million. We implemented interim rates during July 2015. A procedural schedule has been established and discovery is in process. A hearing is scheduled for October 2015. We expect an order on this filing by the end of 2015.

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 ensure 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.

Montana Electric Tracker Filings

Each year we submit an electric tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. 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 2015 annual electric supply tracker filing for the 2014/2015 tracker period and received an order from the MPSC approving the filing on an interim basis. Our electric supply tracker filings for the 2013/2014 and 2012/2013 tracker periods are part of a consolidated docket, which is still subject to final approval by the MPSC. 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 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. Discovery is currently in process and a hearing is scheduled for October 2015.

Montana Lost Revenue Adjustment Mechanism

Demand-side management (DSM) lowers our sales to customers. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM. 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. The appeal is pending. The District Court approved a partial settlement of our appeal, in which the MPSC agreed to remove from the October 2013 order the sentence that imposed the new burden of proof and to initiate a separate docket to review lost revenue policy issues.

The MPSC held a hearing in June 2015 and we expect an order during the fourth quarter of 2015.

Based on the MPSC's October 2013 order, we have recognized $7.1 million of DSM lost revenues for each annual electric supply tracker period. However, 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 a portion of the DSM lost revenues we have recognized since July 2012.

Montana Natural Gas Tracker Filings and Natural Gas Production Assets

In December 2013 and in August 2012, we completed transactions to purchase additional natural gas production interests in northern Montana's Bear Paw Basin (Bear Paw). We are collecting the cost of service for natural gas produced from these assets, including a return on our investment, through our natural gas supply tracker on an interim basis. As a result, we do not expect to file an application with the MPSC to place these assets in natural gas rate base until our next natural gas rate case. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $42.3 million of revenue, a portion of which may be subject to refund.

Each year we submit a 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 natural gas supply procurement activities were prudent.

During the second quarter of 2015, we filed our 2015 annual natural gas supply tracker filing for the 2014/2015 tracker period and received an order from the MPSC approving the filing on an interim basis. Our annual natural gas supply tracker filings for the 2013/2014 and 2012/2013 tracker periods are part of a consolidated docket, which is still subject to final approval by the MPSC. Under the consolidated docket, the Montana Consumer Counsel (MCC) filed testimony that included a recommendation to reduce our natural gas production rates. We disagree with the MCC's recommendation and filed rebuttal testimony. A hearing was held in June 2015 and we expect an order during the third quarter of 2015. If the MPSC ultimately adopts the MCC's recommendation, it could result in refunds of approximately $3.0 million previously recognized as revenue.

(5) Income Taxes

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



	Three Months Ended June 30,
	2015					2014
Income Before Income Taxes	$	39,184				$	8,950

Income tax calculated at 35% federal statutory rate	13,715			35.0	%	3,132			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	367			0.9		(6		)	—
Flow-through repairs deductions	(4,848		)	(12.4	)	(1,779		)	(19.9	)
Production tax credits	(651		)	(1.7	)	(324		)	(3.6	)
Plant and depreciation of flow through items	(245		)	(0.6	)	93			1.0
Other, net	(127		)	(0.2	)	88			1.0
	(5,504		)	(14.0	)	(1,928		)	(21.5	)

Income tax expense	$	8,211		21.0	%	$	1,204		13.5	%



	Six Months Ended June 30,
	2015					2014
Income Before Income Taxes	$	100,625				$	62,523

Income tax calculated at 35% federal statutory rate	35,219			35.0	%	21,883			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	528			0.6		365			0.6
Flow-through repairs deductions	(14,461		)	(14.4	)	(11,472		)	(18.3	)
Production tax credits	(1,912		)	(1.9	)	(1,754		)	(2.8	)
Plant and depreciation of flow through items	(626		)	(0.6	)	503			0.8
Other, net	(521		)	(0.6	)	(328		)	(0.6	)
	(16,992		)	(16.9	)	(12,686		)	(20.3	)

Income tax expense	$	18,227		18.1	%	$	9,197		14.7	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of bonus depreciation deductions 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 $98.1 million as of June 30, 2015, including approximately $66.0 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 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 June 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, 2014, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

There were no changes in our goodwill during the six months ended June 30, 2015. Goodwill by segment is as follows for both June 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
	June 30, 2015								June 30, 2014
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(56	)	$	—	$	(56	)	$	(82	)	$	—	$	(82	)
Reclassification of net gains on derivative instruments	(143		)	52		$	(91	)	(297		)	114		$	(183	)
Other comprehensive loss	$	(199	)	$	52	$	(147	)	$	(379	)	$	114	$	(265	)



	Six Months Ended
	June 30, 2015								June 30, 2014
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	212		$	—	$	212		$	21		$	—	$	21
Reclassification of net gains on derivative instruments	(286		)	106		$	(180	)	(594		)	228		$	(366	)
Other comprehensive (loss) income	$	(74	)	$	106	$	32		$	(573	)	$	228	$	(345	)

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):



	June 30, 2015			December 31, 2014
Foreign currency translation	$	1,009		$	797
Derivative instruments designated as cash flow hedges	(8,496		)	(8,316		)
Pension and postretirement medical plans	(1,247		)	(1,247		)
Accumulated other comprehensive loss	$	(8,734	)	$	(8,766	)

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



		June 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		$	(8,405	)	$	(1,247	)	$	1,065		$	(8,587	)
Other comprehensive income before reclassifications		—			—			(56		)	(56		)
Amounts reclassified from AOCI	Interest Expense	(91		)	—			—			(91		)
Net current-period other comprehensive loss		(91		)	—			(56		)	(147		)
Ending balance		$	(8,496	)	$	(1,247	)	$	1,009		$	(8,734	)



		June 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		$	3,330		$	(1,329	)	$	635		$	2,636
Other comprehensive income before reclassifications		—			—			(82		)	(82		)
Amounts reclassified from AOCI	Interest Expense	(183		)	—			—			(183		)
Net current-period other comprehensive loss		(183		)	—			(82		)	(265		)
Ending balance		$	3,147		$	(1,329	)	$	553		$	2,371



		June 30, 2015
		Six 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		—			—			212		212
Amounts reclassified from AOCI	Interest Expense	(180		)	—			—		(180		)
Net current-period other comprehensive (loss) income		(180		)	—			212		32
Ending balance		$	(8,496	)	$	(1,247	)	$	1,009	$	(8,734	)



		June 30, 2014
		Six 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		—			—			21		21
Amounts reclassified from AOCI	Interest Expense	(366		)	—			—		(366		)
Net current-period other comprehensive (loss) income		(366		)	—			21		(345		)
Ending balance		$	3,147		$	(1,329	)	$	553	$	2,371

(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 June 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 $12.4 million is remaining in AOCI as of June 30, 2015, and we expect to reclassify approximately $0.6 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)
June 30, 2015
Restricted cash	$	13,170	$	—	$	—	$	—	$	13,170
Rabbi trust investments	21,320		—		—		—		21,320
Total	$	34,490	$	—	$	—	$	—	$	34,490

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):



	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,712,111	$	1,793,811	$	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

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.

(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
June 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	221,362		$	49,198		$	—		$	—	$	270,560
Cost of sales	65,918			13,609			—			—		79,527
Gross margin	155,444			35,589			—			—		191,033
Operating, general and administrative	60,838			21,800			(20,918		)	—		61,720
Property and other taxes	25,080			7,371			3			—		32,454
Depreciation and depletion	28,493			7,226			8			—		35,727
Operating income (loss)	41,033			(808		)	20,907			—		61,132
Interest expense	(19,748		)	(2,748		)	(447		)	—		(22,943		)
Other income (expense)	1,659			700			(1,364		)	—		995
Income tax (expense) benefit	(3,558		)	1,217			(5,870		)	—		(8,211		)
Net income (loss)	$	19,386		$	(1,639	)	$	13,226		$	—	$	30,973
Total assets	$	3,994,221		$	1,057,958		$	7,889		$	—	$	5,060,068
Capital expenditures	$	63,926		$	10,706		$	—		$	—	$	74,632



Three Months Ended
June 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	206,010		$	64,271		$	—		$	—	$	270,281
Cost of sales	87,438			25,036			—			—		112,474
Gross margin	118,572			39,235			—			—		157,807
Operating, general and administrative	49,269			22,653			2,445			—		74,367
Property and other taxes	20,326			7,645			3			—		27,974
Depreciation and depletion	23,119			7,241			9			—		30,369
Operating income (loss)	25,858			1,696			(2,457		)	—		25,097
Interest expense	(14,469		)	(2,595		)	(2,063		)	—		(19,127		)
Other income	1,055			415			1,510			—		2,980
Income tax (expense) benefit	(1,673		)	65			404			—		(1,204		)
Net income (loss)	$	10,771		$	(419	)	$	(2,606	)	$	—	$	7,746
Total assets	$	2,637,376		$	1,144,287		$	10,114		$	—	$	3,791,777
Capital expenditures	$	54,507		$	5,836		$	—		$	—	$	60,343



Six Months Ended
June 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	457,408		$	159,163		$	—		$	—	$	616,571
Cost of sales	129,837			62,081			—			—		191,918
Gross margin	327,571			97,082			—			—		424,653
Operating, general and administrative	120,893			43,711			(21,761		)	—		142,843
Property and other taxes	50,339			14,896			6			—		65,241
Depreciation and depletion	57,047			14,482			17			—		71,546
Operating income	99,292			23,993			21,738			—		145,023
Interest expense	(39,446		)	(5,742		)	(870		)	—		(46,058		)
Other income (expense)	2,941			842			(2,123		)	—		1,660
Income tax expense	(9,811		)	(3,504		)	(4,912		)	—		(18,227		)
Net income	$	52,976		$	15,589		$	13,833		$	—	$	82,398
Total assets	$	3,994,221		$	1,057,958		$	7,889		$	—	$	5,060,068
Capital expenditures	$	113,987		$	17,183		$	—		$	—	$	131,170



Six Months Ended
June 30, 2014	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	440,521		$	199,483		$	—		$	—	$	640,004
Cost of sales	189,034			90,868			—			—		279,902
Gross margin	251,487			108,615			—			—		360,102
Operating, general and administrative	96,405			45,249			4,795			—		146,449
Property and other taxes	40,909			15,604			6			—		56,519
Depreciation and depletion	46,224			14,446			17			—		60,687
Operating income (loss)	67,949			33,316			(4,818		)	—		96,447
Interest expense	(29,638		)	(5,352		)	(4,103		)	—		(39,093		)
Other income	1,867			540			2,762			—		5,169
Income tax (expense) benefit	(5,810		)	(4,260		)	873			—		(9,197		)
Net income (loss)	$	34,368		$	24,244		$	(5,286	)	$	—	$	53,326
Total assets	$	2,637,376		$	1,144,287		$	10,114		$	—	$	3,791,777
Capital expenditures	$	99,664		$	12,356		$	—		$	—	$	112,020

(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
	June 30, 2015	June 30, 2014
Basic computation	47,043,735	39,137,307
Dilutive effect of
Performance share awards (1)	243,961	75,316

Diluted computation	47,287,696	39,212,623



	Six Months Ended
	June 30, 2015	June 30, 2014
Basic computation	47,010,546	38,997,321
Dilutive effect of
Performance share awards (1)	247,696	71,966

Diluted computation	47,258,242	39,069,287

______________

(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 June 30,						Three Months Ended June 30,
	2015			2014			2015			2014
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,718		$	2,416		$	134		$	107
Interest cost	6,545			6,529			210			219
Expected return on plan assets	(7,861		)	(7,376		)	(242		)	(246		)
Amortization of prior service cost	61			61			(441		)	(499		)
Recognized actuarial loss	2,699			502			112			97
Net Periodic Benefit Cost (Income)	$	4,162		$	2,132		$	(227	)	$	(322	)



	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Components of Net Periodic Benefit Cost (Income)
Service cost	$	6,181		$	5,415		$	263		$	233
Interest cost	13,087			13,074			393			430
Expected return on plan assets	(15,781		)	(14,753		)	(485		)	(491		)
Amortization of prior service cost	123			123			(941		)	(999		)
Recognized actuarial loss	5,317			1,059			193			174
Net Periodic Benefit Cost (Income)	$	8,927		$	4,918		$	(577	)	$	(653	)

(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 June 30, 2015, we have a reserve of approximately $28.6 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations. 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 $21.6 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 $10.5 million, and we estimate that approximately $7.6 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 risk assessment is being prepared for the Missoula site, which may require additional investigation work. 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 GHG emissions of the very largest emitters, including large power plants, under the Clean Air Act, and specifically under the Prevention of Significant Deterioration (PSD) program, the Title V operating permit programs and the New Source Performance Standards (NSPS).

In January, 2014, the EPA reproposed NSPS specifying permissible levels of GHG emissions for newly-constructed fossil fuel-fired electric generating units and in June 2014 proposed performance standards for modified and reconstructed power plants. Also in June, 2014, the EPA proposed the Clean Power Plan (CPP) rule to control carbon dioxide emissions from existing fossil fuel fired electric generating units. The rule proposes the establishment of statewide GHG emission standards for individual states based on the state's potential to shift generation to existing natural gas combined cycle plants, to develop new renewable energy, to achieve demand-side management savings, and to improve performance at existing coal-fired units. Under the proposed CPP, States would be required to submit individual plans for achieving GHG emission standards to EPA by summer 2016, although under certain circumstances additional time to summer, 2018, would be permitted. The initial performance period for compliance would commence in 2020, with full implementation by 2030. The EPA has indicated that it intends to issue final rules on the NSPS, the performance standards for modified and reconstructed plants and the CPP in August 2015.

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 PSD program, which includes most electric generating units.

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 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 cannot predict with any certainty whether these risks will have a material impact on our operations.

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 that would 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 have been consolidated for review in the Fourth Circuit Court of Appeals.

In April 2013, the EPA proposed CWA regulations to address mercury, arsenic, lead, and selenium in water discharged from power plants. The proposed regulations include a variety of options for whether and how these different waste streams should be treated. The EPA is reviewing public comments on these options prior to enacting final regulations. Under the proposed approach, new requirements for existing power plants would be phased in between 2017 and 2022. The EPA is under a modified consent decree to take final action by September 30, 2015. The EPA estimates that over half of the existing power plants will not incur costs under any of the proposed options because many power plants already have the technology and procedures in place to meet the proposed pollution control standards; 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 to decide how to conform its 2014 decision with the Supreme Court’s ruling. The MATS rule provides for a three-year compliance deadline with the potential for one- and two-year extensions as provided under the statute. 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. At this time, we cannot predict whether the challengers will appeal this decision.

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 various regulations that have been issued or proposed under the Clean Air Act, as discussed below.

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 June 30, 2015, we have capitalized costs of approximately $91.8 million (including allowance for funds used during construction) related to this project, which is expected to be operational by the end of 2015.

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.

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 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. The motions for summary judgment are in the process of being briefed. A bench trial is scheduled for November 16, 2015.

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 June 30, 2015 include:

•

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. See Note 14 - Commitments and Contingencies, to the Condensed Consolidated Financial Statements for additional information.


•	Issuance of $200 million 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, to refinance our 6.04% $150 million first mortgage bonds due 2016.

RESULTS OF OPERATIONS

Net income for the three months ended June 30, 2015 was $31.0 million, or $0.65 per diluted share, as compared with net income of $7.7 million, or $0.20 per diluted share, for the same period in 2014. This increase in net income for the quarter is due to the combination of an insurance recovery related to electric generation environmental remediation costs previously incurred and the results 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 June 30, 2015 Compared with the Three Months Ended June 30, 2014



	Three Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	221.4	$	206.0	$	15.4		7.5	%
Natural Gas	49.2		64.3		(15.1		)	(23.5	)
	$	270.6	$	270.3	$	0.3		0.1	%



	Three Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	65.9	$	87.4	$	(21.5	)	(24.6	)%
Natural Gas	13.6		25.0		(11.4		)	(45.6	)
	$	79.5	$	112.4	$	(32.9	)	(29.3	)%



	Three Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	155.5	$	118.6	$	36.9		31.1	%
Natural Gas	35.6		39.3		(3.7		)	(9.4	)
	$	191.1	$	157.9	$	33.2		21.0	%

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



	Gross Margin 2015 vs. 2014
	(in millions)
Hydro operations	$	38.3
Electric retail volumes	1.6
Electric transmission capacity	0.7
Electric QF adjustment	(4.3		)
Natural gas retail volumes	(1.6		)
Gas production deferral	(1.2		)
Other	(0.3		)
Increase in Consolidated Gross Margin	$	33.2

Consolidated gross margin increased $33.2 million primarily due to the following:


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


•	An increase in electric retail volumes due primarily to warmer spring weather; and


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

These increases were partly offset by:


•	A $6.1 million increase in our QF liability 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 decrease in natural gas retail volumes due primarily to warmer spring weather; and


•	A deferral of initial interim gas production rate revenue compared to actual costs.



	Three Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	61.7	$	74.4	(12.7		)	(17.1	)%
Property and other taxes	32.5		28.0		4.5			16.1
Depreciation and depletion	35.7		30.4		5.3			17.4
	$	129.9	$	132.8	$	(2.9	)	(2.2	)%

Consolidated operating, general and administrative expenses were $61.7 million for the three months ended June 30, 2015, as compared with $74.4 million for the three months ended June 30, 2014. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2015 vs. 2014
	(in millions)
Insurance recovery, net	$	(20.8	)
Non-employee directors deferred compensation	(2.9		)
Bad debt expense	(1.7		)
Hydro Transaction costs	(0.9		)
Hydro operations	11.2
Employee benefit and compensation costs	1.2
Other	1.2
Decrease in Operating, General & Administrative Expenses	$	(12.7	)

The decrease in operating, general and administrative expenses of $12.7 million was primarily due to the following:


•	An insurance recovery primarily associated with electric generation related environmental remediation costs incurred in prior periods;

•

Non-employee directors deferred compensation decreased as compared to the prior year, primarily due to a decrease in our stock price during the three months ended June 30, 2015. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes down, deferred compensation expense decreases; 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;


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


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

These decreases were partly offset by the following:


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


•	Higher employee benefit costs primarily due to higher medical expenses.

Property and other taxes were $32.5 million for the three months ended June 30, 2015, as compared with $28.0 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 $3.7 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 June 30, 2015, as compared with $30.4 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 June 30, 2015 was $61.1 million, as compared with $25.1 million in the same period of 2014. This increase was due to the combination of the insurance recovery discussed above and the impacts of our Hydro Transaction.

Consolidated interest expense for the three months ended June 30, 2015 was $22.9 million, as compared with $19.1 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 June 30, 2015, was $1.0 million, as compared with $3.0 million in the same period of 2014. This decrease was primarily due to a $2.9 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) partially offset by higher capitalization of AFUDC.

Consolidated income tax expense for the three months ended June 30, 2015 was $8.2 million, as compared with $1.2 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 21.0% for the three months ended June 30, 2015 as compared with 13.5% for the same period of 2014. We currently expect our effective tax rate to range between 15% - 19% for 2015.



	Three Months Ended June 30,
	2015					2014
Income Before Income Taxes	$	39.2				$	9.0

Income tax calculated at 35% federal statutory rate	13.7			35.0	%	3.1			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	0.4			0.9		—			—
Flow-through repairs deductions	(4.9		)	(12.4	)	(1.8		)	(19.9	)
Production tax credits	(0.7		)	(1.7	)	(0.3		)	(3.6	)
Plant and depreciation of flow through items	(0.2		)	(0.6	)	0.1			1.0
Other, net	(0.1		)	(0.2	)	0.1			1.0
	(5.5		)	(14.0	)	(1.9		)	(21.5	)

Income tax expense	$	8.2		21.0	%	$	1.2		13.5	%

Consolidated net income for the three months ended June 30, 2015 was $31.0 million as compared with $7.7 million for the same period in 2014. This increase was due to the combination of the insurance recovery as discussed above and the impacts of our Hydro Transaction.

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014



	Six Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	457.4	$	440.5	$	16.9		3.8	%
Natural Gas	159.2		199.5		(40.3		)	(20.2	)
	$	616.6	$	640.0	$	(23.4	)	(3.7	)%



	Six Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	129.8	$	189.0	$	(59.2	)	(31.3	)%
Natural Gas	62.1		90.9		(28.8		)	(31.7	)
	$	191.9	$	279.9	$	(88.0	)	(31.4	)%



	Six Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	327.6	$	251.5	$	76.1		30.3	%
Natural Gas	97.1		108.6		(11.5		)	(10.6	)
	$	424.7	$	360.1	$	64.6		17.9	%

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



	Gross Margin 2015 vs. 2014
	(in millions)
Hydro operations	$	80.4
Electric transmission capacity	1.2
Electric and natural gas retail volumes	(11.0		)
Electric QF adjustment	(4.3		)
Gas production deferral	(1.2		)
Other	(0.5		)
Increase in Consolidated Gross Margin	$	64.6

Consolidated gross margin increased $64.6 million primarily due to the following:


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


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

These increases were partly offset by:


•	An decrease in electric and natural gas retail volumes due primarily to warmer winter and spring weather;


•	A $6.1 million increase in the QF liability 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 deferral of initial interim gas production rate revenue compared to actual costs.



	Six Months Ended June 30,
	2015		2014		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	142.8	$	146.4	$	(3.6	)	(2.5	)%
Property and other taxes	65.2		56.5		8.7			15.4
Depreciation and depletion	71.6		60.7		10.9			18.0
	$	279.6	$	263.6	$	16.0		6.1	%

Consolidated operating, general and administrative expenses were $142.8 million for the six months ended June 30, 2015, as compared with $146.4 million for the six months ended June 30, 2014. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2015 vs. 2014
	(in millions)
Insurance recovery, net	$	(20.8	)
Non-employee directors deferred compensation	(4.9		)
Bad debt expense	(2.8		)
Hydro Transaction costs	(1.7		)
Hydro operations	21.9
Employee benefit and compensation costs	3.2
Other	1.5
Decrease in Operating, General & Administrative Expenses	$	(3.6	)

The decrease in operating, general and administrative expenses of $3.6 million was primarily due to the following:


•	A net insurance recovery primarily associated with electric generation related environmental remediation costs incurred in prior periods;


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


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


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

These decreases were partly offset by the following:


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


•	Higher employee benefit costs primarily due to higher medical expense and compensation costs.

Property and other taxes were $65.2 million for the six months ended June 30, 2015, as compared with $56.5 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 $7.4 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 $71.6 million for the six months ended June 30, 2015, as compared with $60.7 million in the same period of 2014. This increase was primarily due to plant additions, including approximately $8.3 million of hydro related depreciation.

Consolidated operating income for the six months ended June 30, 2015 was $145.0 million, as compared with $96.4 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 six months ended June 30, 2015 was $46.1 million, as compared with $39.1 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 six months ended June 30, 2015, was $1.7 million, as compared with $5.2 million in the same period of 2014. This decrease was primarily due to a $4.9 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) partially offset by higher capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, 2015 was $18.2 million, as compared with $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 18.1% for the six months ended June 30, 2015 as compared with 14.7% for the six months ended June 30, 2014.



	Six Months Ended June 30,
	2015					2014
Income Before Income Taxes	$	100.6				$	62.5

Income tax calculated at 35% federal statutory rate	35.2			35.0	%	21.9			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	0.5			0.6		0.4			0.6
Flow-through repairs deductions	(14.5		)	(14.4	)	(11.5		)	(18.3	)
Production tax credits	(1.9		)	(1.9	)	(1.8		)	(2.8	)
Plant and depreciation of flow through items	(0.6		)	(0.6	)	0.5			0.8
Other, net	(0.5		)	(0.6	)	(0.3		)	(0.6	)
	(17.0		)	(16.9	)	(12.7		)	(20.3	)

Income tax expense	$	18.2		18.1	%	$	9.2		14.7	%

Consolidated net income for the six months ended June 30, 2015 was $82.4 million as compared with $53.3 million for the same period in 2014. This increase was primarily due to the Hydro Transaction and insurance recovery as discussed above.

ELECTRIC SEGMENT

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


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


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


•	Transmission: Reflects transmission revenues regulated by the FERC.


•	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 June 30, 2015 Compared with the Three Months Ended June 30, 2014



	Results
	2015		2014		Change			% Change
	(dollars in millions)
Retail revenues	$	193.7	$	176.4	$	17.3		9.8	%
Regulatory amortization	11.6		14.6		(3.0		)	(20.5	)
Total retail revenues	205.3		191.0		14.3			7.5
Transmission	13.4		12.7		0.7			5.5
Regulation services	0.4		0.5		(0.1		)	(20.0	)
Other	2.3		1.8		0.5			27.8
Total Revenues	221.4		206.0		15.4			7.5
Total Cost of Sales	65.9		87.4		(21.5		)	(24.6	)
Gross Margin	$	155.5	$	118.6	$	36.9		31.1	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Electric
Montana	$	61,261	$	52,951	506	497	286,903	282,840
South Dakota	9,933		11,126		108	121	49,739	49,504
Residential	71,194		64,077		614	618	336,642	332,344
Montana	85,586		76,744		780	770	64,539	63,589
South Dakota	16,836		17,801		224	231	12,508	12,350
Commercial	102,422		94,545		1,004	1,001	77,047	75,939
Industrial	11,177		10,093		574	543	75	75
Other	8,899		7,667		52	47	6,230	6,104
Total Retail Electric	$	193,692	$	176,382	2,244	2,209	419,994	414,462



	Degree Days			2015 as compared with:
Cooling Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	107	8	41	1238% warmer	161% warmer
South Dakota	69	77	64	10% colder	8% warmer



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	1,097	1,244	1,289	12% warmer	15% warmer
South Dakota	1,180	1,532	1,409	23% warmer	16% warmer

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



	Gross Margin 2015 vs. 2014
	(in millions)
Hydro operations	$	38.3
Retail volumes	1.6
Transmission capacity	0.7
QF adjustment	(4.3		)
Other	0.6
Increase in Gross Margin	$	36.9

This increase in gross margin was primarily due to the following:


•	An increase in generation margin due to the November 2014 Hydro Transaction;


•	An increase in retail volumes due primarily to warmer spring weather in Montana; and


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

These increases were partly offset by a $6.1 million increase in the QF liability 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.

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. In addition, 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.

The decrease 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. In addition, while heating and cooling degree days may fluctuate significantly during the second quarter, our electric customer usage is not highly sensitive to these changes between the heating and cooling seasons.

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014



	Results
	2015		2014		Change			% Change
	(dollars in millions)
Retail revenues	$	413.7	$	385.8	$	27.9		7.2	%
Regulatory amortization	10.6		23.9		(13.3		)	(55.6	)
Total retail revenues	424.3		409.7		14.6			3.6
Transmission	27.3		26.1		1.2			4.6
Regulation services	0.8		0.9		(0.1		)	(11.1	)
Other	5.0		3.8		1.2			31.6
Total Revenues	457.4		440.5		16.9			3.8
Total Cost of Sales	129.8		189.0		(59.2		)	(31.3	)
Gross Margin	$	327.6	$	251.5	$	76.1		30.3	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Electric
Montana	$	140,988	$	132,759	1,172	1,229	286,427	282,546
South Dakota	24,655		26,522		292	321	49,756	49,532
Residential	165,643		159,281		1,464	1,550	336,183	332,078
Montana	175,425		157,548		1,573	1,583	64,454	63,534
South Dakota	35,874		36,380		481	487	12,415	12,258
Commercial	211,299		193,928		2,054	2,070	76,869	75,792
Industrial	22,992		20,283		1,140	1,083	75	75
Other	13,794		12,349		76	70	5,402	5,375
Total Retail Electric	$	413,728	$	385,841	4,734	4,773	418,529	413,320



	Degree Days			2015 as compared with:
Cooling Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	107	8	41	1238% warmer	161% warmer
South Dakota	69	77	64	10% colder	8% warmer



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	3,988	4,719	4,595	15% warmer	13% warmer
South Dakota	5,269	6,158	5,529	14% warmer	5% warmer

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



	Gross Margin 2015 vs. 2014
	(in millions)
Hydro operations	$	80.4
Transmission capacity	1.2
QF adjustment	(4.3		)
Retail volumes	(2.8		)
Other	1.6
Increase in Gross Margin	$	76.1

This increase in gross margin was primarily due to the same reasons discussed in the three months ended section above, with a decrease in retail volumes from warmer winter weather partly offset by an increase in volumes from warmer spring weather. In addition, 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. The decrease 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.

NATURAL GAS SEGMENT

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


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


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


•	Wholesale: Primarily represents transportation and storage for others.

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



	Results
	2015		2014			Change			% Change
	(dollars in millions)
Retail revenues	$	36.9	$	55.6		$	(18.7	)	(33.6	)%
Regulatory amortization	2.4		(1.9		)	4.3			226.3
Total retail revenues	39.3		53.7			(14.4		)	(26.8	)
Wholesale and other	9.9		10.6			(0.7		)	(6.6	)
Total Revenues	49.2		64.3			(15.1		)	(23.5	)
Total Cost of Sales	13.6		25.0			(11.4		)	(45.6	)
Gross Margin	$	35.6	$	39.3		$	(3.7	)	(9.4	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Gas
Montana	$	15,666	$	23,762	1,826	1,985	165,954	163,868
South Dakota	4,423		6,369		472	639	38,697	38,478
Nebraska	3,643		5,156		384	512	36,800	36,759
Residential	23,732		35,287		2,682	3,136	241,451	239,105
Montana	8,026		12,214		976	1,040	22,989	22,790
South Dakota	2,886		4,893		493	641	6,262	6,128
Nebraska	1,880		2,612		310	365	4,627	4,616
Commercial	12,792		19,719		1,779	2,046	33,878	33,534
Industrial	159		288		21	26	263	261
Other	169		274		24	29	152	153
Total Retail Gas	$	36,852	$	55,568	4,506	5,237	275,744	273,053



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	1,097	1,244	1,289	12% warmer	15% warmer
South Dakota	1,180	1,532	1,409	23% warmer	16% warmer
Nebraska	981	1,134	1,151	13% warmer	15% warmer

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



	Gross Margin 2015 vs. 2014
	(in millions)
Retail volumes	$	(1.6	)
Gas production deferral	(1.2		)
Other	(0.9		)
Decrease in Gross Margin	$	(3.7	)

This decrease in gross margin was primarily due to a decrease in retail volumes from warmer spring weather 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. The increase 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.

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014



	Results
	2015			2014			Change			% Change
	(dollars in millions)
Retail revenues	$	138.6		$	177.3		$	(38.7	)	(21.8	)%
Regulatory amortization	(0.6		)	(0.3		)	(0.3		)	(100.0	)
Total retail revenues	138.0			177.0			(39.0		)	(22.0	)
Wholesale and other	21.2			22.5			(1.3		)	(5.8	)
Total Revenues	159.2			199.5			(40.3		)	(20.2	)
Total Cost of Sales	62.1			90.9			(28.8		)	(31.7	)
Gross Margin	$	97.1		$	108.6		$	(11.5	)	(10.6	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2015		2014		2015	2014	2015	2014
	(in thousands)
Retail Gas
Montana	$	55,497	$	75,129	6,588	7,556	165,785	163,754
South Dakota	18,174		20,769		2,038	2,436	38,893	38,637
Nebraska	15,079		17,228		1,703	1,962	37,011	36,941
Residential	88,750		113,126		10,329	11,954	241,689	239,332
Montana	27,921		38,302		3,424	4,244	22,981	22,771
South Dakota	12,132		14,944		1,868	2,113	6,289	6,155
Nebraska	8,538		9,405		1,240	1,385	4,660	4,643
Commercial	48,591		62,651		6,532	7,742	33,930	33,569
Industrial	725		785		92	83	263	263
Other	555		754		80	94	152	153
Total Retail Gas	$	138,621	$	177,316	17,033	19,873	276,034	273,317



	Degree Days			2015 as compared with:
Heating Degree-Days	2015	2014	Historic Average	2014	Historic Average
Montana	3,988	4,719	4,595	15% warmer	13% warmer
South Dakota	5,269	6,158	5,529	14% warmer	5% warmer
Nebraska	4,355	4,712	4,570	8% warmer	5% warmer

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



	Gross Margin 2015 vs. 2014
	(in millions)
Retail volumes	$	(8.2	)
Gas production deferral	(1.2		)
Other	(2.1		)
Decrease in Gross Margin	$	(11.5	)

This decrease in gross margin was primarily due to a decrease in retail volumes from warmer winter and spring weather 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. 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. The financing for the South Dakota wind generation acquisition is expected to be up to $70 million in long-term debt, up to $60 million in common stock and the remainder from cash flows from operations. 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 June 30, 2015, our total net liquidity was approximately $163.0 million, including $32.9 million of cash and $130.1 million of revolving credit facility availability. Revolving credit facility availability was $165.1 million as of July17, 2015. During the second quarter of 2015, we issued $200 million of first mortgage bonds. Proceeds were used to redeem $150 million of first mortgage bonds due in 2016 and finance incremental Montana capital expenditures.

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



Amount outstanding at period end	$	219.9
Daily average amount outstanding	$	204.7
Maximum amount outstanding	$	242.9

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 June 30, 2015, we are under collected on our natural gas and electric trackers by approximately $9.2 million, as compared with an under collection of $33.0 million as of December 31, 2014, and an under collection of $32.6 million as of June 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 July 17, 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):



	Six Months Ended June 30,
	2015			2014
Operating Activities
Net income	$	82.4		$	53.3
Non-cash adjustments to net income	90.3			95.4
Changes in working capital	7.5			(6.4		)
Other	10.2			(17.8		)
	190.4			124.5

Investing Activities
Property, plant and equipment additions	(131.2		)	(112.0		)
Change in restricted cash	9.2			—
Acquisitions	(0.5		)	1.5
Other	0.1			0.1
	(122.4		)	(110.4		)

Financing Activities
Proceeds from issuance of common stock, net	—			13.3
Issuances (repayments) of long-term debt, net	50.0			(0.1		)
(Repayments) issuances of short-term borrowings, net	(47.9		)	5.0
Dividends on common stock	(44.8		)	(30.9		)
Financing costs	(11.7		)	—
Other	(1.1		)	(1.1		)
	(55.5		)	(13.8		)

Increase in Cash and Cash Equivalents	$	12.5		$	0.3
Cash and Cash Equivalents, beginning of period	$	20.4		$	16.6
Cash and Cash Equivalents, end of period	$	32.9		$	16.9

Cash Provided by Operating Activities

As of June 30, 2015, cash and cash equivalents were $32.9 million as compared with $20.4 million at December 31, 2014 and $16.9 million at June 30, 2014. Cash provided by operating activities totaled $190.4 million for the six months ended June 30, 2015 as compared with $124.5 million during the six months ended June 30, 2014. This increase in operating cash flows is primarily due to higher net income and a reduction in our under collection of supply costs in our trackers during the current period. 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 $12.0 million as compared with the first six months of 2014. Plant additions during 2015 include maintenance additions of approximately $85.8 million, supply related capital expenditures of approximately $19.8 million, primarily related to electric generation facilities in South Dakota, and Distribution System Infrastructure Project (DSIP) capital expenditures of approximately $25.6 million. Plant additions during the first six months of 2014 include maintenance additions of approximately $68.4 million, supply related capital expenditures of approximately $20.4 million, which were primarily related to electric generation facilities in South Dakota, and DSIP capital expenditures of approximately $22.2 million.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $55.5 million during the six months ended June 30, 2015 as compared with approximately $13.8 million during the six months ended June 30, 2014. During the six months ended June 30, 2015, net cash used in financing activities includes net repayments of commercial paper of $47.9 million, the payment of dividends of $44.8 million and the payment of financing costs of $11.7 million, offset in part by net proceeds from the issuance of debt of $50.0 million. During the six months ended June 30, 2014, net cash used in financing activities consisted of the payment of dividends of $30.9 million, offset in part by proceeds received from the issuance of common stock pursuant to our equity distribution agreement of $13.3 million and net issuances of commercial paper of $5.0 million.

Debt Issuance - 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 June 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	$	1,712,111	$	—	$	—	$	—	$	55,000	$	250,000	$	1,407,111
Capital leases	29,055		893		1,837		1,979		2,133		2,298		19,915
Short-term borrowings	219,909		219,909		—		—		—		—		—
Future minimum operating lease payments	4,414		1,098		1,732		893		168		90		433
Estimated pension and other postretirement obligations (1)	66,797		12,489		13,680		13,626		13,554		13,448		N/A
Qualifying facilities liability (2)	990,509		35,215		72,629		74,684		76,782		78,918		652,281
Supply and capacity contracts (3)	1,541,268		106,976		166,781		134,343		106,937		103,497		922,734
Contractual interest payments on debt (4)	1,414,522		37,024		81,685		81,542		79,759		68,862		1,065,650
Environmental remediation obligations (1)	7,627		1,527		2,000		1,600		1,700		800		N/A
Total Commitments (5)	$	5,986,212	$	415,131	$	340,344	$	308,667	$	336,033	$	517,913	$	4,068,124

_________________________


(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 0.65% 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 June 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 June 30, 2015, we had approximately $219.9 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.

Market prices for electricity are currently low. For the period in 2015 that we own the Kerr Project and taking into account purchased power commitments, we expect to have more generation output than our customer demand. The first-year regulated revenue requirement for the Hydro Transaction includes credits for our customers from the sale of generated electricity that exceeds our needs. The MPSC order approving the Hydro Transaction authorizes us to track these revenue credits on a portfolio basis. If the amount of electricity available for sale is lower than expected from our owned generation resources, or if market prices for electricity that is sold are lower than expected, we may not realize the anticipated revenue credits. The MPSC may disallow recovery of any shortfall in revenue credits.

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.

In a separate matter, 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. The appeal is pending. The District Court approved a partial settlement of our appeal, in which the MPSC agreed to remove from the October 2013 order the sentence that imposed the new burden of proof and to initiate a separate docket to review lost revenue policy issues. The MPSC held a hearing in June 2015 and we expect an order during the fourth quarter of 2015. We have been deferring a portion of lost revenues currently being collected from customers, pending an order from the MPSC. There is risk that the MPSC may ultimately require us to refund more lost revenues than we have deferred, 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.

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 (MRO) for our South Dakota operations and the Western Electricity Coordination Council (WECC) 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. 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 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.

We have financial risks associated with our temporary ownership of the Kerr Project.

The MPSC order approving the Hydro Transaction provides that our customers will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing to that effect required upon completion of the transfer of the project to CSKT. Accordingly, the Kerr Project and the associated assets are not included in our regulatory rate base. While we own the Kerr Project and taking into account purchased power commitments, we expect to have more generation output than our customers can use. The first-year revenue requirement for the Hydro Transaction includes revenue credits from the sale of generated electricity that exceeds our needs. The MPSC order approving the Hydro Transaction authorizes us to track these revenue credits on a portfolio basis. If the amount of electricity available for sale is lower than expected from our owned generation resources, or if the market prices for electricity that is sold are lower than expected, we may not realize the anticipated revenue credits. Market prices for electricity are currently very low and if revenues from sales to third parties during 2015 are lower than anticipated, the MPSC may disallow recovery of any shortfall in revenue credits.

We also bear the risk of any damage to the Kerr Project that occurs during our temporary ownership, except to the extent that costs associated with remediating any damage represent an addition or improvement to the Kerr Project that may increase the conveyance price pursuant to the Kerr Project license. The costs associated with such repairs could be substantial and may not be fully covered by any insurance. To the extent any such costs are not covered by insurance, they could have a material adverse effect on our financial condition and results of operations.

We may fail to realize the anticipated benefits of the Hydro Transaction.

We may be unable to achieve the strategic, operational, financial and other benefits, contemplated by us with respect to the Hydro Transaction to the full extent expected or in a timely manner. We may not achieve expected cost savings, rate of return, accretion to earnings and cash flows, increased electricity generation, and other anticipated benefits and opportunities from the Hydro Transaction, or they may take longer to realize than expected.

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. As directed by President Obama's Climate Action Plan, on June 2, 2014, the EPA proposed the Clean Power Plan rule to control carbon dioxide

emissions from existing fossil fuel fired electric generating units. The EPA has expressed the intent to finalize those regulations and guidelines in August 2015.

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.

In addition, we have experienced unscheduled outages at DGGS, due primarily to component failures within several of the gas generators and power turbines. We have continued to meet our regulation service responsibilities, and have not acquired replacement regulation service during this time. Although the plant is expected to remain in service throughout the repair period, the amount of available regulation service will vary as equipment is repaired and returned to service. We do not currently anticipate needing to acquire any regulation service from third parties during this time. If we should need to acquire regulation service, there can be no assurance that the MPSC and/or FERC would allow us full recovery of such costs.

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 4.1—Thirty-fifth Supplemental Indenture, dated as of June 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 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:	July 23, 2015	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX



Exhibit Number		Description
4.1		Thirty-fifth Supplemental Indenture, dated as of June 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 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