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, 2014
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. 69th 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

39,139,724 shares outstanding at July 18, 2014

1

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 Balance Sheets — June 30, 2014 and December 31, 2013	4
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, 2014 and 2013	5
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2014 and 2013	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2014 and 2013	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
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 5.	Other Information	55
Item 6.	Exhibits	56
SIGNATURES		57

2

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:

• potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, as well as adverse determinations by regulators, 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.

In addition, actual results may differ materially from those contemplated in any forward-looking statement due to the timing and likelihood of the closing of the purchase of PPL Montana LLC's hydro-electric generating facilities (Hydro Transaction). See Note 3 - Hydro Transaction, to the Condensed Consolidated Financial Statements for additional information relative to this transaction.

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.

3

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30, 2014			December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	16,934		$	16,557
Restricted cash	15,560			6,896
Accounts receivable, net	130,342			174,913
Inventories	52,925			55,609
Regulatory assets	50,858			37,719
Deferred income taxes	11,707			14,301
Other	12,331			14,961
Total current assets	290,657			320,956
Property, plant, and equipment, net	2,747,877			2,690,128
Goodwill	355,128			355,128
Regulatory assets	336,837			316,952
Other noncurrent assets	61,278			32,096
Total assets	$	3,791,777		$	3,715,260
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,684		$	1,662
Short-term borrowings	145,951			140,950
Accounts payable	63,970			92,957
Accrued expenses	167,521			181,613
Regulatory liabilities	51,781			46,406
Total current liabilities	430,907			463,588
Long-term capital leases	29,055			29,895
Long-term debt	1,182,086			1,155,097
Deferred income taxes	425,085			395,333
Noncurrent regulatory liabilities	355,525			348,053
Other noncurrent liabilities	301,966			292,624
Total liabilities	2,724,624			2,684,590
Commitments and Contingencies (Note 14)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,752,477 and 39,139,365 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	428			423
Treasury stock at cost	(92,701		)	(91,744		)
Paid-in capital	925,578			910,184
Retained earnings	231,477			209,091
Accumulated other comprehensive income	2,371			2,716
Total shareholders' equity	1,067,153			1,030,670
Total liabilities and shareholders' equity	$	3,791,777		$	3,715,260

See Notes to Condensed Consolidated Financial Statements

4

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues
Electric	$	206,010		$	200,472		$	440,521		$	410,564
Gas	64,271			59,362			199,483			161,880
Other	—			327			—			737
Total Revenues	270,281			260,161			640,004			573,181
Operating Expenses
Cost of sales	112,474			106,913			279,902			239,109
Operating, general and administrative	74,367			67,364			146,449			136,201
Property and other taxes	27,974			25,810			56,519			51,569
Depreciation and depletion	30,369			27,414			60,687			56,632
Total Operating Expenses	245,184			227,501			543,557			483,511
Operating Income	25,097			32,660			96,447			89,670
Interest Expense, net	(19,127		)	(17,141		)	(39,093		)	(33,920		)
Other Income	2,980			928			5,169			3,643
Income Before Income Taxes	8,950			16,447			62,523			59,393
Income Tax Expense	(1,204		)	(2,106		)	(9,197		)	(7,150		)
Net Income	$	7,746		$	14,341		$	53,326		$	52,243
Average Common Shares Outstanding	39,137			38,092			38,997			37,740
Basic Earnings per Average Common Share	$	0.20		$	0.37		$	1.37		$	1.38
Diluted Earnings per Average Common Share	$	0.20		$	0.37		$	1.37		$	1.38
Dividends Declared per Common Share	$	0.40		$	0.38		$	0.80		$	0.76

See Notes to Condensed Consolidated Financial Statements

5

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,
	2014		2013		2014			2013
Net Income	7,746		14,341		$	53,326		$	52,243
Other comprehensive (loss) income, net of tax:
Reclassification of net gains on derivative instruments	(183	)	(183	)	(366		)	(366		)
Foreign currency translation	(82	)	86		21			135
Total Other Comprehensive Loss	(265	)	(97	)	(345		)	(231		)
Comprehensive Income	7,481		14,244		$	52,981		$	52,012

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2014			2013
OPERATING ACTIVITIES:
Net income	$	53,326		$	52,243
Items not affecting cash:
Depreciation and depletion	60,687			56,632
Amortization of debt issue costs, discount and deferred hedge gain	3,226			193
Amortization of restricted stock	1,531			1,249
Equity portion of allowance for funds used during construction	(2,541		)	(2,194		)
Gain on disposition of assets	(107		)	(705		)
Deferred income taxes	32,575			32,393
Changes in current assets and liabilities:
Restricted cash	(8,664		)	(1,368		)
Accounts receivable	44,571			27,169
Inventories	2,684			6,551
Other current assets	2,630			(7,007		)
Accounts payable	(26,323		)	(23,617		)
Accrued expenses	(13,500		)	(8,632		)
Regulatory assets	(13,139		)	11,584
Regulatory liabilities	5,375			(73		)
Other noncurrent assets	(25,237		)	(25,336		)
Other noncurrent liabilities	7,468			10,729
Cash provided by operating activities	124,562			129,811
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(112,020		)	(88,549		)
Asset acquisition	1,455			—
Proceeds from sale of assets	147			747
Cash used in investing activities	(110,418		)	(87,802		)
FINANCING ACTIVITIES:
Treasury stock activity	(957		)	(1,179		)
Proceeds from issuance of common stock, net	13,329			43,781
Dividends on common stock	(30,940		)	(28,627		)
Repayments on long-term debt	(57		)	(73		)
Issuance (Repayments) of short-term borrowings, net	5,002			(57,940		)
Financing costs	(144		)	—
Cash used in financing activities	(13,767		)	(44,038		)
Increase (Decrease) in Cash and Cash Equivalents	377			(2,029		)
Cash and Cash Equivalents, beginning of period	16,557			9,822
Cash and Cash Equivalents, end of period	$	16,934		$	7,793
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	20		$	42
Interest	31,756			29,175
Significant non-cash transactions:
Capital expenditures included in accounts payable and accrued expenses	7,360			9,081

See Notes to Condensed Consolidated Financial Statements

7

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 678,200 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, 2014, 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, 2013.

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 $274.9 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance will be effective for us in our first quarter of 2017. Early adoption is not permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

8

Accounting Standards Adopted

There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the six months ended June 30, 2014 that are of significance, or potential significance, to us.

(3) Hydro Transaction

On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to adjustment for proration of operating expenses, performance of planned capital expenditures, and termination of certain power purchase agreements.

The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility. The Federal Energy Regulatory Commission (FERC) license for the Kerr Project gives the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. After the CSKT complete their acquisition of the Kerr Project in September 2015, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.

Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the FERC, the Montana Public Service Commission (MPSC), other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act). In March 2014, FERC issued an order to approve the transfer of licenses for the Thompson Falls, Missouri-Madison and Mystic Lake Hydro-Electric Projects; and indicated it would process the transfer of the license for the Kerr Project in a separate proceeding. In April 2014, we received approval of the required HSR Act filing. In May 2014, FERC issued orders under Sections 203 and 205 of the Federal Power Act approving the asset transfer and continuation of wholesale power sales at market-based rates after the transaction. We expect to receive FERC approval of the license transfer for the Kerr Project during the third quarter of 2014.

In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction. The filing initiates the formal regulatory process necessary to complete the previously announced $900 million agreement, and includes a request to include the hydro assets in rate base and to issue the securities necessary to complete the purchase. Our original request was based on a return on equity of 10%, a capital structure of 52% debt and 48% equity, and an estimated first year average rate base of $866 million. In May 2014, we filed rebuttal testimony with adjustments to increase the average depreciable life of the assets and remove the Kerr Project from our rate base request, which reduced the estimated first year average rate base to $839 million. A hearing was held in July 2014 and we anticipate a decision from the MPSC in September 2014.

Assuming receipt of a reasonably satisfactory approval from the MPSC we will be seeking authority from FERC to issue securities in connection with the Hydro Transaction. We anticipate that FERC approval to issue securities may take up to 60 days from the date of MPSC approval of the Hydro Transaction. Either we or PPLM may terminate the agreement if the closing does not occur by September 26, 2014; however, this date will be extended for an additional six months if any regulatory approval is still pending.

The permanent financing for the Hydro Transaction is anticipated to be a combination of long-term debt, new equity issuance and cash flows from operations. The Hydro Transaction is supported by a fully committed $900 million364-day senior bridge credit facility.

During the six months ended June 30, 2014, we incurred approximately $1.7 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $3.8 million of expenses related to the bridge credit facility included in interest expense.

9

(4) Regulatory Matters

Hydro Transaction

See Note 3 - Hydro Transaction.

Dave Gates Generating Station at Mill Creek (DGGS)

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 have been recognizing revenue consistent with the ALJ's initial decision. As of June 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.

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. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the second half of 2014. 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 could, depending on when the FERC issues a rehearing order 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. Based on the FERC order, we are also assessing the potential for various additional filings at FERC for additional cost recovery. We anticipate making additional filings at FERC during the second half of 2014. 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.

Montana Electric and Natural Gas Tracker Filings

Each year we submit electric and natural gas tracker filings 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 and natural gas supply procurement activities were prudent.

In May 2014, we filed our 2014 annual electric and natural gas supply tracker filings for the 2013/2014 tracker period. The MPSC consolidated the 2014 tracker filing with our pending 2013 filing for the 2012/2013 tracker period. During June 2014, we received orders from the MPSC approving the 2014 annual electric and natural gas supply tracker filings on an interim basis.

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 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. Procedural schedules have not yet been established for the consolidated electric or natural gas supply tracker dockets.

During October 2013, the MPSC approved an order related to our 2012 electric supply tracker filing (covering July 1, 2011 through June 30, 2012), which included a decision on a review of an independent study related to our request for demand-side management (DSM) lost revenues and addresses future DSM lost revenue recovery. The order also included a provision expressing concern with the policy of continuing to allow DSM lost revenue recovery, indicating that we bear the burden of demonstrating why any incremental DSM lost revenue recovery from the date of its October 2013 order forward is reasonable and in the public interest. We appealed the decision to the Montana District Court and during the second quarter of 2014, the MPSC agreed to initiate a separate proceeding related to the evaluation of DSM lost revenue recovery. A procedural schedule has not yet been established.

Based on the MPSC's October 2013 order, we expect to be able to collect at least $7.1 million of DSM lost revenues for each annual tracker period; however, since the 2012/2013 annual tracker filing is 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.

10

Natural Gas Production Assets

In 2012 and 2013, we purchased 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 $21.2 million of revenue that is subject to refund.

(5) Income Taxes

The following table reconciles our effective income tax rate to the federal statutory rate:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
State income, net of federal provisions	—		(3.4	)	0.6		(3.3	)
Flow-through repairs deductions	(19.9	)	(12.8	)	(18.3	)	(16.5	)
Production tax credits	(3.6	)	(3.1	)	(2.8	)	(2.8	)
Prior year permanent return to accrual adjustments	—		3.3		—		0.9
Plant and depreciation of flow through items	1.0		(4.9	)	0.8		—
Other, net	1.0		(1.3	)	(0.6	)	(1.3	)
	13.5	%	12.8	%	14.7	%	12.0	%

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of 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 have unrecognized tax benefits of approximately $115.0 million as of June 30, 2014, including approximately $80.1 million that, if recognized, would impact our effective tax rate. It is reasonably possible that our unrecognized tax benefits may decrease by up to $20 million in the next 12 months due to the expiration of statutes of limitation and a potential accounting method change.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2014, we did not recognize expense for interest or penalties in the Condensed Consolidated Statement of Income. As of June 30, 2014 and December 31, 2013, we had $0.4 million of interest accrued in the Condensed Consolidated Balance Sheets. During the six months ended June 30, 2013, we did not recognize expense for interest or penalties and did not have any amounts accrued for the payment of interest and penalties.

In September 2013, the Internal Revenue Service (IRS) issued final tangible property regulations, which include guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations were effective January 1, 2014. The most substantial area of the regulations is determining if an expenditure related to tangible property is a repair or should be capitalized. In recent years, we filed changes in the method of accounting related to repairs of utility property. We will file accounting method changes to comply with the regulations as issued, but do not expect the changes to have a material effect on our financial position or results of operations.

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

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(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, 2014. Goodwill by segment is as follows for both June 30, 2014 and December 31, 2013 (in thousands):

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

(7) Comprehensive (Loss) Income

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

	June 30, 2014
	Three Months Ended								Six Months Ended
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(82	)	$	—	$	(82	)	$	21		$	—	$	21
Reclassification of net gains on derivative instruments to net income	(297		)	114		$	(183	)	(594		)	228		(366		)
Other comprehensive loss	$	(379	)	$	114	$	(265	)	$	(573	)	$	228	$	(345	)

	June 30, 2013
	Three Months Ended								Six Months Ended
	Before-Tax Amount			Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	86		$	—	$	86		$	135		$	—	$	135
Reclassification of net gains on derivative instruments to net income	(297		)	114		(183		)	(594		)	228		(366		)
Other comprehensive loss	$	(211	)	$	114	$	(97	)	$	(459	)	$	228	$	(231	)

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

	June 30, 2014			December 31, 2013
Foreign currency translation	$	553		$	532
Derivative instruments designated as cash flow hedges	3,147			3,513
Pension and postretirement medical plans	(1,329		)	(1,329		)
Accumulated other comprehensive income	$	2,371		$	2,716

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

		June 30, 2014
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Gains on 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 accumulated other comprehensive income	Interest Expense	(183		)	—			—			(183		)
Net current-period other comprehensive (loss) income		(183		)	—			(82		)	(265		)
Ending balance		$	3,147		$	(1,329	)	$	553		$	2,371

		June 30, 2013
		Three Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Gains on Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	4,060		$	(2,292	)	$	415	$	2,183
Other comprehensive income before reclassifications		—			—			86		86
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(183		)	—			—		(183		)
Net current-period other comprehensive (loss) income		(183		)	—			86		(97		)
Ending balance		$	3,877		$	(2,292	)	$	501	$	2,086

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		June 30, 2014
		Six Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Gains on 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 accumulated other comprehensive income	Interest Expense	(366		)	—			—		(366		)
Net current-period other comprehensive (loss) income		(366		)	—			21		(345		)
Ending balance		$	3,147		$	(1,329	)	$	553	$	2,371

		June 30, 2013
		Six Months Ended
	Affected Line Item in the Condensed Consolidated Statements of Income	Gains on Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	4,243		$	(2,292	)	$	366	$	2,317
Other comprehensive income before reclassifications		—			—			135		135
Amounts reclassified from accumulated other comprehensive income	Interest Expense	(366		)	—			—		(366		)
Net current-period other comprehensive (loss) income		(366		)	—			135		(231		)
Ending balance		$	3,877		$	(2,292	)	$	501	$	2,086

(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 large 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.

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Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. 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, in the past we have used and in the future 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, 2014 and December 31, 2013. 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

We are exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. 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 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. 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

15

expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements (in thousands):

	Location of gain reclassified from AOCI to Income	Six Months Ended June 30, 2014 and 2013
Amount of gain reclassified from AOCI	Interest Expense	$	594

Approximately $5.1 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of June 30, 2014, and we expect to reclassify approximately $1.2 million from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

(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. Normal purchases and sales 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.

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	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, 2014
Restricted cash	$	15,349	$	—	$	—	$	—	$	15,349
Rabbi trust investments	22,477		—		—		—		22,477
Total	$	37,826	$	—	$	—	$	—	$	37,826
December 31, 2013
Restricted cash	$	6,650	$	—	$	—	$	—	$	6,650
Rabbi trust investments	16,477		—		—		—		16,477
Total	$	23,127	$	—	$	—	$	—	$	23,127

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, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,182,086	$	1,315,047	$	1,155,097	$	1,237,151

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 April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share, with proceeds of approximately $13.4 million, which are net of sales commissions of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.

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(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 is not considered a business unit. Other primarily consists of the wind down of our captive insurance subsidiary and our 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, 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

Three Months Ended
June 30, 2013	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	200,472		$	59,362		$	327		$	—	$	260,161
Cost of sales	82,520			24,393			—			—		106,913
Gross margin	117,952			34,969			327			—		153,248
Operating, general and administrative	47,721			18,483			1,160			—		67,364
Property and other taxes	19,016			6,792			2			—		25,810
Depreciation and depletion	21,693			5,712			9			—		27,414
Operating income (loss)	29,522			3,982			(844		)	—		32,660
Interest expense	(14,411		)	(2,567		)	(163		)	—		(17,141		)
Other income	702			198			28			—		928
Income tax expense	(76		)	(1,901		)	(129		)	—		(2,106		)
Net income (loss)	$	15,737		$	(288	)	$	(1,108	)	$	—	$	14,341
Total assets	$	2,486,588		$	1,054,550		$	9,910		$	—	$	3,551,048
Capital expenditures	$	41,691		$	8,744		$	—		$	—	$	50,435

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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

Six Months Ended
June 30, 2013	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	410,564		$	161,880		$	737		$	—	$	573,181
Cost of sales	165,615			73,494			—			—		239,109
Gross margin	244,949			88,386			737			—		334,072
Operating, general and administrative	93,439			38,378			4,384			—		136,201
Property and other taxes	38,168			13,396			5			—		51,569
Depreciation and depletion	45,304			11,311			17			—		56,632
Operating income (loss)	68,038			25,301			(3,669		)	—		89,670
Interest expense	(28,538		)	(4,993		)	(389		)	—		(33,920		)
Other income	2,713			875			55			—		3,643
Income tax (expense) benefit	(4,380		)	(3,673		)	903			—		(7,150		)
Net income (loss)	$	37,833		$	17,510		$	(3,100	)	$	—	$	52,243
Total assets	$	2,486,588		$	1,054,550		$	9,910		$	—	$	3,551,048
Capital expenditures	$	75,006		$	13,543		$	—		$	—	$	88,549

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(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 restricted stock and performance share awards.

Average shares used in computing the basic and diluted earnings per share are as follows:

	Three Months Ended
	June 30, 2014	June 30, 2013
Basic computation	39,137,307	38,092,292
Dilutive effect of
Restricted stock and performance share awards (1)	75,316	129,347
Diluted computation	39,212,623	38,221,639

	Six Months Ended
	June 30, 2014	June 30, 2013
Basic computation	38,997,321	37,740,316
Dilutive effect of
Restricted stock and performance share awards (1)	71,966	125,422
Diluted computation	39,069,287	37,865,738

_______________

(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,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,416		$	3,294		$	107		$	115
Interest cost	6,529			5,736			219			222
Expected return on plan assets	(7,376		)	(8,121		)	(246		)	(256		)
Amortization of prior service cost	61			61			(499		)	(499		)
Recognized actuarial loss	502			3,072			97			261
Net Periodic Benefit Cost (Income)	$	2,132		$	4,042		$	(322	)	$	(157	)

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	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Components of Net Periodic Benefit Cost (Income)
Service cost	$	5,415		$	6,733		$	233		$	271
Interest cost	13,074			11,360			430			439
Expected return on plan assets	(14,753		)	(16,246		)	(491		)	(510		)
Amortization of prior service cost	123			123			(999		)	(999		)
Recognized actuarial loss	1,059			5,824			174			486
Net Periodic Benefit Cost (Income)	$	4,918		$	7,794		$	(653	)	$	(313	)

(14) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

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. 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.

Our liability for environmental remediation obligations is estimated to range between $27.3 million to $35.0 million, primarily for manufactured gas plants discussed below. As of June 30, 2014, we have a reserve of approximately $27.4 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. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately $22.6 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 $11.6 million, and we estimate that approximately $8.5 million of this amount will be incurred during the next five years.

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

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In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. 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. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary and additional monitoring wells will be installed at the Butte site. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended period of time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site 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 have undivided interests in these facilities and 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) pre-construction permit, the Title V operating permit programs and the New Source Performance Standards (NSPS). In 2014, the EPA reproposed NSPS that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units.

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 rule proposes the establishment of statewide reductions of GHG emissions 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. The EPA intends to finalize those regulations and guidelines by June 1, 2015. States must then submit their individual plans for achieving GHG emission standards to EPA by June 30, 2016, although EPA is proposing a dual-phase submittal process for state plans that would allow for additional time to June 30, 2018 under certain circumstances. The initial performance period for compliance would commence in 2020, with full implementation by 2030.

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.

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. In addition, physical impacts of climate change may present potential risks for severe weather, such as 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 June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C, the hazardous waste provisions, of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. In a January 2014 consent decree in the case Appalachian Voices v. McCarthy, the EPA agreed to take final action with respect to the CCR

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regulations by December 19, 2014. In addition, legislation has been introduced in Congress to regulate coal ash. We cannot predict at this time the final requirements of any CCR regulations or legislation and what impact, if any, they would have on us, but the costs of complying with any such requirements could be significant.

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. On May 19, 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 gives seven options for meeting BTA, and provides a more flexible compliance approach than the proposed 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.

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 where 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. Facilities that are subject to the MATS must come into compliance by April 2015, unless a one year extension is granted on a case-by-case basis. On April 15, 2014, the U.S. Court of Appeals for the D.C. Circuit upheld the MATS rule. The decision is expected to be appealed to the Supreme Court.

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. On April 29, 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. It is anticipated that further proceedings will occur in the U.S. Court of Appeals for the D.C. Circuit and at EPA to establish new compliance deadlines.

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 Unit 4 does 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, 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 have challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. The Ninth Circuit held oral argument on the petition on May 16, 2014. At this time, we cannot predict or determine the timing or outcome of this petition.

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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, of 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. During the first quarter of 2014, the estimated total project cost for the AQCS was reduced from $405 million to approximately $384 million (our share is 23.4%) and it is expected to be operational by 2016. As of June 30, 2014, we have capitalized costs of approximately $56.4 million related to this project.

Our incremental capital expenditure projections include amounts related to our share of the BART at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The South Dakota Public Utilities Commission has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.

Based on the finalized MATS, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. In August 2013, the South Dakota DENR granted Big Stone a one year extension to comply with MATS, such that the new compliance deadline is April 16, 2016. New mercury emissions monitoring equipment will also be required.

North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of 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 finalized MATS, Coyote will meet the requirements by using activated carbon injection for mercury control.

Iowa. The Neal #4 generating facility, of which we have an 8.7% ownership, installed a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. The project was substantially completed in 2013.

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. The owners do not believe additional equipment will be necessary to meet the MATS for mercury, and anticipate meeting all other expected MATS emissions limitations required by the rule without additional costs except those costs related to increased monitoring frequency. These additional costs are not expected to be significant.

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.

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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 against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station. 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 drops 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 have identified physical changes made at Colstrip between 2001 and 2012, which they allege have increased emissions of SO₂, NOx and particulate matter and were “major modifications” subject to permitting requirements under the Clean Air Act. They also have alleged violations of the requirements related to Part 70 Operating Permits. Plaintiffs seek 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.

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 Court has not ruled on Plaintiffs’ motion for partial summary judgment.

The Parties filed a joint notice (Notice) on April 21, 2014 that advises the Court of Plaintiffs’ intent to file a Second Amended Complaint which will drop claims relating to 52 projects, but will add one additional project, for a total of 13 projects remaining in the Complaint. The Plaintiffs have also agreed that there will be no additional projects in any future Amended Complaint. The Court has further extended various deadlines previously set and has set a bench trial date for the liability portion of the case for June 8, 2015.

On May 6, 2014, the Court held oral argument on the Colstrip owners’ motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the Court issued findings and recommendation, 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.

On June 5, 2014, Plaintiffs filed an objection to the Court’s findings and recommendations. On June 19, 2014, the Colstrip owners filed a response to Plaintiffs’ objection. Briefing on the objection is not yet complete, and there has been no ruling on the objection.

We intend to vigorously defend this lawsuit. Due to the preliminary nature of the 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.

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.

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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 678,200 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, 2013.

SIGNIFICANT ITEMS

Hydro Transaction

On September 26, 2013, we entered into an agreement with PPL Montana, a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to adjustment for proration of operating expenses, performance of planned capital expenditures, and termination of certain power purchase agreements.

The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility. The Federal Energy Regulatory Commission (FERC) license for the Kerr Project gives the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million. Under our agreement with PPL Montana, the $900 million purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. If the Hydro Transaction is completed, we expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. After the CSKT complete their acquisition of the Kerr Project in September 2015, we will own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana.

Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the FERC, the Montana Public Service Commission (MPSC), other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act). In March 2014, FERC issued an order to approve the transfer of licenses for the Thompson Falls, Missouri-Madison and Mystic Lake Hydro-Electric Projects; and indicated it would process the transfer of the license for the Kerr Project in a separate proceeding. In April 2014, we received approval of the required HSR Act filing. In May 2014, FERC issued orders under Sections 203 and 205 of the Federal Power Act approving the asset transfer and continuation of wholesale power sales at market-based rates after the transaction. We expect to receive FERC approval of the license transfer for the Kerr Project during the third quarter of 2014.

In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction. The filing initiates the formal regulatory process necessary to complete the previously announced $900 million agreement, and includes a request to include the hydro assets in rate base and to issue the securities necessary to complete the purchase. Our original request was based on a return on equity of 10%, a capital structure of 52% debt and 48% equity, and an estimated first year average rate base of $866 million. In May 2014, we filed rebuttal testimony with adjustments to increase the average depreciable life of the assets and remove the Kerr Project from our rate base request, which reduced the estimated first year average rate base to $839 million. A hearing was held in July 2014 and we anticipate a decision from the MPSC in September 2014.

Assuming receipt of a reasonably satisfactory approval from the MPSC we will be seeking authority from FERC to issue securities in connection with the Hydro Transaction. We anticipate that FERC approval to issue securities may take up to 60 days from the date of MPSC approval of the Hydro Transaction. Either we or PPLM may terminate the agreement if the closing does not occur by September 26, 2014; however, this date will be extended for an additional six months if any regulatory approval is still pending.

The permanent financing for the Hydro Transaction is anticipated to be a combination of long-term debt, new equity issuance and cash flows from operations. The Hydro Transaction is supported by a fully committed $900 million364-day senior bridge credit facility.

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During the six months ended June 30, 2014, we incurred approximately $1.7 million of legal and professional fees associated with the Hydro Transaction, which are included in operating, general and administrative expense, and approximately $3.8 million of expenses related to the bridge credit facility included in interest expense.

Dave Gates Generating Station at Mill Creek (DGGS)

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 have been recognizing revenue consistent with the ALJ's initial decision. As of June 30, 2014, we have cumulative deferred revenue of approximately $27.3 million, which is subject to refund and recorded within current regulatory liabilities in the Condensed Consolidated Balance Sheets. The order included a requirement to issue customer refunds (included in deferred revenue) within 30 days.

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. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the second half of 2014. 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 could, depending on when the FERC issues a rehearing order 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. Based on the FERC order, we are also assessing the potential for various additional filings at FERC for additional cost recovery. We anticipate making additional filings at FERC during the second half of 2014. 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.

Natural Gas Production Assets

In 2012 and 2013, we purchased natural gas production interests in northern Montana's Bear Paw Basin. 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 $21.2 million of revenue that is subject to refund.

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RESULTS OF OPERATIONS

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

Non-GAAP Financial Measure

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

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OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, 2014 Compared with the Three Months Ended June 30, 2013

	Three Months Ended June 30,
	2014		2013		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	206.0	$	200.5	$	5.5		2.7	%
Natural Gas	64.3		59.4		4.9			8.2
Other	—		0.3		(0.3		)	(100.0	)
	$	270.3	$	260.2	$	10.1		3.9	%

	Three Months Ended June 30,
	2014		2013		Change		% Change
	(dollars in millions)
Cost of Sales
Electric	$	87.4	$	82.5	$	4.9	5.9	%
Natural Gas	25.0		24.4		0.6		2.5
	$	112.4	$	106.9	$	5.5	5.1	%

	Three Months Ended June 30,
	2014		2013		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	118.6	$	118.0	$	0.6		0.5	%
Natural Gas	39.3		35.0		4.3			12.3
Other	—		0.3		(0.3		)	(100.0	)
	$	157.9	$	153.3	$	4.6		3.0	%

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

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	5.1
DSM lost revenues	1.0
Natural gas retail volumes	$	(0.9	)
Other	(0.6		)
Increase in Consolidated Gross Margin	$	4.6

Consolidated gross margin increased $4.6 million primarily due to an increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, for which the revenues are subject to refund; and an increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers, offset in part by a decrease in retail volumes due primarily to warmer spring weather.

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	Three Months Ended June 30,
	2014		2013		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	74.4	$	67.4	$	7.0	10.4	%
Property and other taxes	28.0		25.8		2.2		8.5
Depreciation and depletion	30.4		27.4		3.0		10.9
	$	132.8	$	120.6	$	12.2	10.1	%

Consolidated operating, general and administrative expenses were $74.4 million for the three months ended June 30, 2014, as compared with $67.4 million for the three months ended June 30, 2013. Primary components of the change include the following:

	Operating, General & Administrative Expenses
	2014 vs. 2013
	(in millions)
Natural gas production	$	2.9
Bad debt expense	2.2
Nonemployee directors deferred compensation	1.5
Hydro Transaction costs	0.9
Other	(0.5		)
Increase in Operating, General & Administrative Expenses	$	7.0

The increase in operating, general and administrative expenses of $7.0 million was primarily due to the following:

• Higher natural gas production costs due to the acquisition of the natural gas production assets discussed above;

• Higher bad debt expense, due to a combination of higher revenues and slower collections of receivables from customers related to our customer information systems implementation;

• Non-employee directors deferred compensation increased as compared to the prior year, primarily due to changes in our stock price. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we account for the deferred shares as trading securities and their increase in value is reflected in other income with no impact on net income; and

• Legal and professional fees associated with the Hydro Transaction. We expect to incur additional Hydro Transaction related legal and professional fees during the remainder of 2014.

Property and other taxes were $28.0 million for the three months ended June 30, 2014, as compared with $25.8 million in the same period of 2013. This increase was primarily due to plant additions and higher estimated property valuations in Montana. 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 $30.4 million for the three months ended June 30, 2014, as compared with $27.4 million in the same period of 2013. This increase was primarily due to plant additions, including approximately $1.2 million related to the acquisition of natural gas production assets.

Consolidated operating income for the three months ended June 30, 2014 was $25.1 million, as compared with $32.7 million in the same period of 2013. This decrease was due to higher operating expenses partly offset by the increase in gross margin as discussed above.

Consolidated interest expense for the three months ended June 30, 2014 was $19.1 million, as compared with $17.1 million in the same period of 2013. This increase includes $1.9 million of expenses associated with the bridge credit facility related to the Hydro Transaction, and higher interest from the issuance in December 2013 of $100 million of long-term debt unrelated to the Hydro Transaction, partly offset by lower interest accrued on revenues subject to refund and higher

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capitalization of AFUDC. We expect interest expense to increase by approximately $1.4 million for the remainder of 2014 as a result of the bridge credit facility.

Consolidated other income for the three months ended June 30, 2014, was $3.0 million, as compared with $0.9 million in the same period of 2013. This increase was primarily due to a $1.5 million gain on deferred shares held in trust for non-employee directors deferred compensation discussed above and higher capitalization of AFUDC.

Consolidated income tax expense for the three months ended June 30, 2014 was $1.2 million, as compared with $2.1 millionin the same period of 2013. Our effective tax rate was 13.5% for the three months ended June 30, 2014 as compared with 12.8% for the three months ended June 30, 2013.

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 millions):

	Three Months Ended June 30,
	2014					2013
Income Before Income Taxes	$	9.0				$	16.4
Income tax calculated at 35% federal statutory rate	3.1			35.0	%	5.8			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	—			—		(0.6		)	(3.4	)
Flow-through repairs deductions	(1.8		)	(19.9	)	(2.1		)	(12.8	)
Production tax credits	(0.3		)	(3.6	)	(0.5		)	(3.1	)
Prior year permanent return to accrual adjustments	—			—		0.5			3.3
Plant and depreciation of flow through items	0.1			1.0		(0.8		)	(4.9	)
Other, net	0.1			1.0		(0.2		)	(1.3	)
	(1.9		)	(21.5	)	(3.7		)	(22.2	)
Income tax expense	$	1.2		13.5	%	$	2.1		12.8	%

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of 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.Consolidated net income for the three months ended June 30, 2014 was $7.7 million as compared with $14.3 million for the same period in 2013. This decrease was primarily due to the lower operating income and higher interest expense as discussed above, partly offset by higher other income and lower income tax expense.

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Six Months Ended June 30, 2014 Compared with the Six Months Ended June 30, 2013

	Six Months Ended June 30,
	2014		2013		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	440.5	$	410.6	$	29.9		7.3	%
Natural Gas	199.5		161.9		37.6			23.2
Other	—		0.7		(0.7		)	(100.0	)
	$	640.0	$	573.2	$	66.8		11.7	%

	Six Months Ended June 30,
	2014		2013		Change		% Change
	(dollars in millions)
Cost of Sales
Electric	$	189.0	$	165.6	$	23.4	14.1	%
Natural Gas	90.9		73.5		17.4		23.7
	$	279.9	$	239.1	$	40.8	17.1	%

	Six Months Ended June 30,
	2014		2013		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	251.5	$	245.0	$	6.5		2.7	%
Natural Gas	108.6		88.4		20.2			22.9
Other	—		0.7		(0.7		)	(100.0	)
	$	360.1	$	334.1	$	26.0		7.8	%

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

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	14.6
Natural gas and electric retail volumes	7.0
Montana natural gas rate increase	4.9
DSM lost revenues	1.5
Other	(2.0		)
Increase in Consolidated Gross Margin	$	26.0

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Consolidated gross margin increased $26.0 million primarily due to the following:

• An increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, for which the revenues are subject to refund;

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

• An increase in Montana natural gas delivery rates implemented in April 2013; and

• An increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers.

	Six Months Ended June 30,
	2014		2013		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	146.4	$	136.2	10.2		7.5	%
Property and other taxes	56.5		51.6		4.9		9.5
Depreciation and depletion	60.7		56.6		4.1		7.2
	$	263.6	$	244.4	$	19.2	7.9	%

Consolidated operating, general and administrative expenses were $146.4 million for the six months ended June 30, 2014, as compared with $136.2 million for the six months ended June 30, 2013. Primary components of the change include the following:

	Operating, General & Administrative Expenses
	2014 vs. 2013
	(in millions)
Natural gas production	$	5.0
Bad debt expense	3.1
Hydro Transaction costs	1.7
Nonemployee directors deferred compensation	1.3
Other	(0.9		)
Increase in Operating, General & Administrative Expenses	$	10.2

The increase in operating, general and administrative expenses of $10.2 million was primarily due to the following:

• Higher natural gas production costs due to the acquisition of the natural gas production assets discussed above;

• Higher bad debt expense, due to a combination of higher revenues and slower collections of receivables from customers related to our customer information systems implementation;

• Legal and professional fees associated with the Hydro Transaction; and

• Non-employee directors deferred compensation increased as compared to the prior year, primarily due to changes in our stock price.

Property and other taxes were $56.5 million for the six months ended June 30, 2014, as compared with $51.6 million in the same period of 2013. This increase was primarily due to plant additions and higher estimated property valuations in Montana.

Depreciation and depletion expense was $60.7 million for the six months ended June 30, 2014, as compared with $56.6 million in the same period of 2013. This increase was primarily due to plant additions, including approximately $2.4 million related to the acquisition of natural gas production assets. These increases were offset in part by a reduction in depreciation rates of approximately $1.5 million as a result of new depreciation studies conducted by an independent consultant and

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implemented during the second quarter of 2013. These studies reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota.

Consolidated operating income for the six months ended June 30, 2014 was $96.4 million, as compared with $89.7 million in the same period of 2013. This increase was due to the increase in gross margin partly offset by higher operating expenses as discussed above.

Consolidated interest expense for the six months ended June 30, 2014 was $39.1 million, as compared with $33.9 million in the same period of 2013. This increase includes $3.8 million of expenses associated with the bridge credit facility related to the Hydro Transaction, higher interest from the issuance in December 2013 of $100 million of long-term debt unrelated to the Hydro Transaction, and interest accrued on revenues subject to refund.

Consolidated other income for the six months ended June 30, 2014, was $5.2 million, as compared with $3.6 million in the same period of 2013. This increase was primarily due to a $1.3 million gain on deferred shares held in trust for non-employee directors deferred compensation discussed above and higher capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, 2014 was $9.2 million, as compared with $7.2 millionin the same period of 2013. Our effective tax rate was 14.7% for the six months ended June 30, 2014 as compared with 12.0% for the six months ended June 30, 2013.

Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of 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.

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 millions):

	Six Months Ended June 30,
	2014					2013
Income Before Income Taxes	$	62.5				$	59.4
Income tax calculated at 35% federal statutory rate	21.9			35.0	%	20.8			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	0.4			0.6		(1.9		)	(3.3	)
Flow-through repairs deductions	(11.5		)	(18.3	)	(9.8		)	(16.5	)
Production tax credits	(1.8		)	(2.8	)	(1.7		)	(2.8	)
Prior year permanent return to accrual adjustments	—			—		0.5			0.9
Plant and depreciation of flow through items	0.5			0.8		—			—
Other, net	(0.3		)	(0.6	)	(0.8		)	(1.3	)
	(12.7		)	(20.3	)	(13.7		)	(23.0	)
Income tax expense	$	9.2		14.7	%	$	7.1		12.0	%

Consolidated net income for the six months ended June 30, 2014 was $53.3 million as compared with $52.2 million for the same period in 2013. This increase was primarily due to the higher operating income and higher other income as discussed above, partly offset by higher interest and income tax expense.

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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, which is also reflected in cost of sales and therefore has minimal impact on gross margin.

• Transmission: Reflects transmission revenues regulated by the FERC.

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

• Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are based on prevailing market prices.

• Other: Miscellaneous electric revenues.

Three Months Ended June 30, 2014 Compared with the Three Months Ended June 30, 2013

	Results
	2014		2013		Change			% Change
	(dollars in millions)
Retail revenues	$	176.4	$	179.9	$	(3.5	)	(1.9	)%
Regulatory amortization	14.6		5.9		8.7			147.5
Total retail revenues	191.0		185.8		5.2			2.8
Transmission	12.7		12.5		0.2			1.6
Ancillary services	0.5		0.4		0.1			25.0
Wholesale	0.8		0.7		0.1			14.3
Other	1.0		1.1		(0.1		)	(9.1	)
Total Revenues	206.0		200.5		5.5			2.7
Total Cost of Sales	87.4		82.5		4.9			5.9
Gross Margin	$	118.6	$	118.0	$	0.6		0.5	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Electric
Montana	$	52,951	$	56,915	497	495	282,840	280,217
South Dakota	11,126		10,628		121	123	49,504	49,222
Residential	64,077		67,543		618	618	332,344	329,439
Montana	76,744		77,086		770	753	63,589	63,070
South Dakota	17,801		16,163		231	222	12,350	12,290
Commercial	94,545		93,249		1,001	975	75,939	75,360
Industrial	10,093		10,583		722	709	75	74
Other	7,667		8,561		47	54	6,104	6,065
Total Retail Electric	$	176,382	$	179,936	2,388	2,356	414,462	410,938
Total Wholesale Electric	$	773	$	670	49	35	—	—

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	Degree Days			2014 as compared with:
Cooling Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	8	45	41	82% cooler	80% cooler
South Dakota	77	50	63	54% warmer	22% warmer

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	1,244	1,267	1,306	2% warmer	5% warmer
South Dakota	1,532	1,897	1,421	19% warmer	8% colder

The following summarizes the components of the changes in electric gross margin for the three months ended June 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
DSM lost revenues	$	1.0
Other	(0.4		)
Increase in Gross Margin	$	0.6

This increase in gross margin was primarily due to an increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers. The increase in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.

Wholesale volumes increased from higher plant utilization in 2014.

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.

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Six Months Ended June 30, 2014 Compared with the Six Months Ended June 30, 2013

	Results
	2014		2013		Change			% Change
	(dollars in millions)
Retail revenues	$	385.8	$	379.9	$	5.9		1.6	%
Regulatory amortization	23.9		0.1		23.8			23,800.0
Total retail revenues	409.7		380.0		29.7			7.8
Transmission	26.1		26.1		—			—
Ancillary services	0.9		0.8		0.1			12.5
Wholesale	1.0		1.2		(0.2		)	(16.7	)
Other	2.8		2.5		0.3			12.0
Total Revenues	440.5		410.6		29.9			7.3
Total Cost of Sales	189.0		165.6		23.4			14.1
Gross Margin	$	251.5	$	245.0	$	6.5		2.7	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Electric
Montana	$	132,759	$	132,921	1,229	1,177	282,546	280,029
South Dakota	26,522		24,452		321	301	49,532	49,198
Residential	159,281		157,373		1,550	1,478	332,078	329,227
Montana	157,548		154,858		1,583	1,533	63,534	63,047
South Dakota	36,380		33,508		487	467	12,258	12,175
Commercial	193,928		188,366		2,070	2,000	75,792	75,222
Industrial	20,283		20,984		1,395	1,456	75	74
Other	12,349		13,221		70	77	5,375	5,288
Total Retail Electric	$	385,841	$	379,944	5,085	5,011	413,320	409,811
Total Wholesale Electric	$	1,017	$	1,177	60	58	—	—

	Degree Days			2014 as compared with:
Cooling Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	8	45	41	82% cooler	80% cooler
South Dakota	77	50	63	54% warmer	22% warmer

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	4,719	4,490	4,581	5% cooler	3% cooler
South Dakota	6,158	6,114	5,519	1% cooler	12% cooler

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The following summarizes the components of the changes in electric gross margin for the six months ended June 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Retail volumes	$	4.7
DSM lost revenues	1.9
Other	(0.1		)
Increase in Gross Margin	$	6.5

This increase in gross margin was primarily due to an increase in retail volumes due primarily to colder winter weather and customer growth, and an increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers. The increase in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin.

Retail volumes increased primarily due to colder winter weather and customer growth. Wholesale volumes remained relatively flat.

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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, 2014 Compared with the Three Months Ended June 30, 2013

	Results
	2014			2013		Change			% Change
	(dollars in millions)
Retail revenues	$	55.6		$	49.1	$	6.5		13.2	%
Regulatory amortization	(1.9		)	1.0		(2.9		)	(290.0	)
Total retail revenues	53.7			50.1		3.6			7.2
Wholesale and other	10.6			9.3		1.3			14.0
Total Revenues	64.3			59.4		4.9			8.2
Total Cost of Sales	25.0			24.4		0.6			2.5
Gross Margin	$	39.3		$	35.0	$	4.3		12.3	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Gas
Montana	$	23,762	$	19,537	1,985	2,046	163,868	162,561
South Dakota	6,369		6,432		639	719	38,478	38,131
Nebraska	5,156		5,604		512	579	36,759	36,624
Residential	35,287		31,573		3,136	3,344	239,105	237,316
Montana	12,214		9,757		1,040	1,049	22,790	22,684
South Dakota	4,893		4,384		641	677	6,128	6,029
Nebraska	2,612		2,958		365	440	4,616	4,594
Commercial	19,719		17,099		2,046	2,166	33,534	33,307
Industrial	288		171		26	19	261	265
Other	274		209		29	29	153	158
Total Retail Gas	$	55,568	$	49,052	5,237	5,558	273,053	271,046

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	1,244	1,267	1,306	2% warmer	5% warmer
South Dakota	1,532	1,897	1,421	19% warmer	8% colder
Nebraska	1,134	1,365	1,162	17% warmer	2% warmer

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The following summarizes the components of the changes in natural gas gross margin for the three months ended June 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	5.1
Retail volumes	(0.9		)
Other	0.1
Increase in Gross Margin	$	4.3

This increase in gross margin was primarily due to an increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, of which the revenues are subject to refund. This increase was partially offset by a decrease in retail volumes due primarily to warmer spring weather.

Average natural gas supply prices increased in 2014 resulting in higher retail revenues and cost of sales as compared with 2013, with no impact to gross margin.

Retail volumes decreased primarily due to warmer spring weather, offset in part by customer growth.

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Six Months Ended June 30, 2014 Compared with the Six Months Ended June 30, 2013

	Results
	2014			2013			Change		% Change
	(dollars in millions)
Retail revenues	$	177.3		$	150.7		$	26.6	17.7	%
Regulatory amortization	(0.3		)	(9.5		)	9.2		(96.8	)
Total retail revenues	177.0			141.2			35.8		25.4
Wholesale and other	22.5			20.7			1.8		8.7
Total Revenues	199.5			161.9			37.6		23.2
Total Cost of Sales	90.9			73.5			17.4		23.7
Gross Margin	$	108.6		$	88.4		$	20.2	22.9	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2014		2013		2014	2013	2014	2013
	(in thousands)
Retail Gas
Montana	$	75,129	$	62,401	7,556	7,207	163,754	162,549
South Dakota	20,769		18,310		2,436	2,230	38,637	38,296
Nebraska	17,228		16,517		1,962	1,855	36,941	36,826
Residential	113,126		97,228		11,954	11,292	239,332	237,671
Montana	38,302		31,296		4,244	3,671	22,771	22,691
South Dakota	14,944		12,202		2,113	1,948	6,155	6,056
Nebraska	9,405		8,735		1,385	1,311	4,643	4,624
Commercial	62,651		52,233		7,742	6,930	33,569	33,371
Industrial	785		631		83	76	263	266
Other	754		626		94	87	153	158
Total Retail Gas	$	177,316	$	150,718	19,873	18,385	273,317	271,466

	Degree Days			2014 as compared with:
Heating Degree-Days	2014	2013	Historic Average	2013	Historic Average
Montana	4,719	4,490	4,581	5% cooler	3% cooler
South Dakota	6,158	6,114	5,519	1% cooler	12% cooler
Nebraska	4,712	4,720	4,562	remained flat	3% cooler

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The following summarizes the components of the changes in natural gas gross margin for the six months ended June 30, 2014 and 2013:

	Gross Margin 2014 vs. 2013
	(in millions)
Natural gas production	$	14.6
Montana natural gas rate increase	4.9
Retail volumes	2.3
Other	(1.6		)
Increase in Gross Margin	$	20.2

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

• An increase in natural gas production margin primarily due to the acquisition of gas production assets in December 2013, for which the revenues are subject to refund;

• An increase in Montana natural gas delivery rates implemented in April 2013; and

• An increase in retail volumes due primarily to colder winter weather and customer growth.

Average natural gas supply prices increased in 2014 resulting in higher retail revenues and cost of sales as compared with 2013, with no impact to gross margin.

Retail volumes increased primarily due to colder winter weather and customer growth.

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LIQUIDITY AND CAPITAL RESOURCES

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, 2014, our total net liquidity was approximately $170.9 million, including $16.9 million of cash and $154.0 million of revolving credit facility availability. Revolving credit facility availability was $162.1 millionas of July 18, 2014.

The following table presents additional information about short term borrowings during the three months ended June 30, 2014 (in millions):

Amount outstanding at period end	$	146.0
Daily average amount outstanding	$	78.8
Maximum amount outstanding	$	146.0

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, including the Hydro Transaction as discussed above, we intend to utilize available cash flow, debt capacity that would allow us to maintain investment grade ratings, and issue equity. In April 2012, we entered into an Equity Distribution Agreement pursuant to which we were able to offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During the three months ended March 31, 2014, we sold 295,979 shares of our common stock at an average price of $45.65 per share. Proceeds received were approximately $13.4 million, which are net of sales commissions paid to UBS of approximately $147,000 and other fees. This concluded our sales pursuant to the Equity Distribution Agreement. Total shares issued under the Equity Distribution Agreement were 2,492,889 at an average price of $40.11, for net proceeds of $98.7 million.

We plan to maintain a 50 - 55% debt to total capital ratio excluding capital leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70% of earnings per share; however, there can be no assurance that we will be able to meet these targets. During 2014, assuming receipt of reasonably satisfactory regulatory approvals related to the Hydro Transaction, we expect to issue approximately $450 - $500 million of debt securities and up to $400 million of equity securities, as well as use up to $50 million cash, to fund the Hydro Transaction. In November 2013, in connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility (bridge facility). The bridge facility may be used temporarily in a single draw to finance the Hydro Transaction and pay related fees and expenses pending completion of the permanent financing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.

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,

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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, 2014, we are under collected on our current Montana natural gas and electric trackers by approximately $32.6 million, as compared with an under collection of $27.3 million as of December 31, 2013, and an under collection of $3.0 million as of June 30, 2013.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, and impact our trade credit availability. Fitch Ratings (Fitch), Moody’s and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 18, 2014, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A-	BBB+	F2	Positive Watch
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.

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Cash Flows

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

	Six Months Ended June 30,
	2014			2013
Operating Activities
Net income	$	53.3		$	52.2
Non-cash adjustments to net income	95.4			87.6
Changes in working capital	(6.4		)	4.6
Other	(17.8		)	(14.6		)
	124.5			129.8
Investing Activities
Property, plant and equipment additions	(112.0		)	(88.5		)
Asset acquisition	1.5			—
Other	0.1			0.7
	(110.4		)	(87.8		)
Financing Activities
Proceeds from issuance of common stock, net	13.3			43.8
Repayments of long-term debt, net	(0.1		)	(0.1		)
Issuance (Repayments) of short-term borrowings, net	5.0			(57.9		)
Dividends on common stock	(30.9		)	(28.6		)
Other	(1.1		)	(1.2		)
	(13.8		)	(44.0		)
Increase in Cash and Cash Equivalents	$	0.3		$	(2.0	)
Cash and Cash Equivalents, beginning of period	$	16.6		$	9.8
Cash and Cash Equivalents, end of period	$	16.9		$	7.8

Cash Provided by Operating Activities

As of June 30, 2014, cash and cash equivalents were $16.9 million as compared with $16.6 million at December 31, 2013 and $7.8 million at June 30, 2013. Cash provided by operating activities totaled $124.5 million for the six months ended June 30, 2014 as compared with $129.8 million during the six months ended June 30, 2013. This decrease in operating cash flows is primarily due to an increase in the under collection of supply costs in our trackers, partially offset by higher collections of customer receivables as compared with 2013.

During September 2013, we implemented a new customer information system. While collections improved during the second quarter of 2014, we are still experiencing delays in collections of customer receivables. We expect continued improvement during the third quarter of 2014.

Cash Used in Investing Activities

Cash used in investing activities increased by approximately $22.6 million as compared with the first six months of 2013. Plant additions during 2014 include maintenance additions of approximately $68.4 million, supply related capital expenditures of approximately $20.4 million, primarily related to electric generation facilities in South Dakota, and Distribution System Infrastructure Project (DSIP) capital expenditures of approximately $22.2 million. Plant additions during the first six months of 2013 include maintenance additions of approximately $51.1 million, supply related capital expenditures of approximately $19.4 million, which were primarily related to electric generation facilities in South Dakota, and DSIP capital expenditures of approximately $17.6 million.

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Cash Used in Financing Activities

Cash used in financing activities totaled approximately $13.8 million during the six months ended June 30, 2014 as compared with approximately $44.0 million during the six months ended June 30, 2013. 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. During the six months ended June 30, 2013, net cash used in financing activities consisted of net repayments of commercial paper of $57.9 million and the payment of dividends of $28.6 million, offset in part by proceeds received from the issuance of common stock pursuant to our equity distribution agreement of $43.8 million.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of June 30, 2014. See our Annual Report on Form 10-K for the year ended December 31, 2013 for additional discussion.

	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Long-term debt	$	1,182,086	$	—	$	—	$	150,000	$	—	$	55,000	$	977,086
Capital leases	30,739		856		1,733		1,837		1,979		2,133		22,201
Short-term borrowings	145,951		145,951		—		—		—		—		—
Future minimum operating lease payments	4,959		1,058		1,786		1,316		545		43		211
Estimated pension and other postretirement obligations (1)	55,869		1,286		13,749		13,695		13,623		13,516		N/A
Qualifying facilities liability (2)	1,048,730		33,642		69,606		71,598		73,622		75,688		724,574
Supply and capacity contracts (3)	1,718,185		171,897		206,902		152,474		128,090		100,438		958,384
Contractual interest payments on debt (4)	723,723		30,996		61,991		61,991		52,931		51,221		464,593
Environmental remediation obligations (1)	8,500		1,200		1,300		2,200		2,200		1,600		N/A
Total Commitments (5)	$	4,918,742	$	386,886	$	357,067	$	455,111	$	272,990	$	299,639	$	3,147,049

_________________________

(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 28 years.

(4) For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 0.39% through maturity.

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

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our Condensed Consolidated Fnancial 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, 2014, 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, 2013. 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.

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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, 2014, we had approximately $146.0 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 $1.5 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. We also participate in the wholesale electric market to balance our supply of power from our own generating resources, primarily in South Dakota. 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, including forward purchase and sales contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is substantially mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

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

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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 reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

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

Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 14, Commitments and Contingencies, to the Financial Statements for information about 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 September 2012, we received a non-binding decision from a FERC ALJ concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. On April 17, 2014, the FERC issued an order affirming the ALJ's decision. 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 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 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. On July 17, 2014, the Montana Environmental Information Center and Sierra Club filed a petition to intervene in our electric tracker dockets to challenge the costs of maintaining and operating Colstrip Unit 4, particularly the costs of replacement power related to the outage, as imprudent. We believe the costs associated with the outage and incremental market purchases were prudently incurred, however, there is risk that the MPSC ultimately disallows all or a portion of these costs.

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We are subject to many FERC rules and orders that regulate our electric and natural gas business. We must also comply with established reliability standards and requirements, which apply to the North American Electric Reliability Corporation (NERC) functions for which we have registered 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, 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.

Our plans for future expansion through the acquisition of assets including hydro-electric generating facilities and 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 complete an acquisition successfully, or to integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

In order to complete the Hydro Transaction, we must still obtain certain approvals from the MPSC and the FERC. These regulatory agencies may not approve the transaction, or may approve the transaction subject to terms or conditions that could delay closing, impose additional costs, impact the transaction's anticipated benefits, or cause the transaction to terminate. In addition, failure to obtain approvals on terms consistent with our application could negatively affect credit ratings and equity valuation, and our ability to invest in our Montana utility operations, including but not limited to supply.

In connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility (bridge facility), which may be used to temporarily finance a significant portion of the acquisition and pay related fees and expenses in the event that permanent financing is not in place at the time of the closing of the transaction. The permanent financing is anticipated to include a mix of long-term debt and common equity. Although we believe we have taken prudent steps to position ourselves for successful capital raises, there can be no assurance as to the ultimate cost or availability of permanent financing.

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.

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

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emissions from existing fossil fuel fired electric generating units. The EPA has expressed the intent to finalize those regulations and guidelines by June 1, 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. As discussed above, 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, most of our generating capacity is coal-fired. We 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 for wholesale sales, 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.

We implemented a new customer information system, and we may experience additional difficulties, delays and interruptions associated with the transition to this new system. Any unexpected significant difficulties in completing the transition could negatively impact our business.

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During September 2013, we implemented a new customer information system. There are inherent risks associated with replacing and changing these types of systems, such as delayed and / or inaccurate customer bills, potential disruption of our business, and substantial unplanned costs, any of which could harm our reputation and have a material adverse effect on our business, financial condition or results of operations.

Consistent with our expectations, we experienced billing delays, which resulted in delays in collections of customer receivables and increased bad debt expense during the transition to the new system. We are still experiencing delays in collections of customer receivables. Any additional unexpected significant difficulties in completing the transition of our customer information system could materially impact our ability to timely and accurately record, process and report information that is important to our business.

Our natural gas distribution services involve numerous activities that may result in accidents and other operating risks and costs.

Inherent in our natural gas distribution services are a variety of hazards and operating risks, such as 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. 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 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.

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 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. As discussed above, in our latest electric tracker filing the treatment of costs for replacement power due to an outage at Colstrip Unit 4 have been identified by the MPSC for additional prudence review. 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.

We currently procure a large portion of our natural gas supply and our Montana electric supply pursuant to 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 gas and/or electricity supply requirements in the energy markets, 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.

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.

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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 3% over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds 3%, 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. 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 an increase in changes in 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 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.

Our business is dependent on our ability to successfully access capital markets on favorable terms. Limits on our access to capital may adversely impact our ability to execute our business plan or pursue improvements that we would otherwise rely on for future growth.

Our cash requirements are driven by the capital-intensive nature of our business. Access to the capital and credit markets, at a reasonable cost, is necessary for us to fund our operations, including capital requirements. We rely on a revolving credit facility and commercial paper market for short-term liquidity needs due to the seasonality of our business, and on capital markets to raise capital for growth projects that are not otherwise provided by operating cash flows. Instability in the financial markets may increase the cost of capital, limit our ability to draw on our revolving credit facility, access the commercial paper market and/or raise capital. If we are unable to obtain the liquidity needed to meet our business requirements on favorable terms, we may defer growth projects and/or capital expenditures.

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.

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We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks 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 (such as hacking and viruses) 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 5. OTHER INFORMATION

As previously reported, on April 24, 2014 at the 2014 Annual Meeting of Stockholders, the stockholders approved the NorthWestern Corporation Amended and Restated Equity Compensation Plan (the Plan), including the performance goals available under the Plan and the issuance of an additional 600,000 shares of common stock. The Plan permits a committee of the Board to grant to designated officers, employees and non-employee directors of NorthWestern and its affiliates incentive awards in the form of performance awards, restricted shares, restricted share units, unrestricted shares, deferred share units, options, share appreciation rights and other awards including the payment of stock in lieu of cash under our other incentive or bonus programs or otherwise and payment of cash based on attainment of performance goals. A more detailed summary of the material features of the Plan is set forth in our proxy statement for the 2014 Annual Meeting of Stockholders filed with the Securities and Exchange Commission on March 7, 2014. A copy of the Plan is included as Appendix A to such proxy statement.

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ITEM 6.                      EXHIBITS

(a)Exhibits

Exhibit 10.1—NorthWestern Corporation Amended and Restated Equity Compensation Plan, as amended effective July 1, 2014 (incorporated by reference to Appendix A to NorthWestern Corporation's Proxy Statement for the 2014 Annual Meeting of Shareholders filed on March 7, 2014, 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

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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 24, 2014	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

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EXHIBIT INDEX

Exhibit Number	Description
10.1	NorthWestern Corporation Amended and Restated Equity Compensation Plan, as amended effective July 1, 2014 (incorporated by reference to Appendix A to NorthWestern Corporation's Proxy Statement for the 2014 Annual Meeting of Shareholders filed on March 7, 2014, 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

58