NORTHWESTERN CORP - Quarter Report: 2016 June (Form 10-Q)

Location of amount reclassified from AOCL to Income

Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2016

Interest rate contracts

Interest Expense

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2016

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-10499

NORTHWESTERN CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		46-0172280
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3010 W. 69^th Street, Sioux Falls, South Dakota		57108
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common Stock, Par Value $0.01

48,311,224 shares outstanding at July 15, 2016

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX



		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Income — Three and Six Months Ended June 30, 2016 and 2015	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2016 and 2015	5
	Condensed Consolidated Balance Sheets — June 30, 2016 and December 31, 2015	6
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2016 and 2015	7
	Condensed Consolidated Statements of Shareholders' Equity — Six Months Ended June 30, 2016 and 2015	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	56
PART II. OTHER INFORMATION		57
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 6.	Exhibits	64
SIGNATURES		65

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:


•	adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;


•	changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;


•	unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and


•	adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.



PART 1. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues
Electric	$	248,403		$	221,362		$	489,745		$	457,408
Gas	44,717			49,198			135,914			159,163
Total Revenues	293,120			270,560			625,659			616,571
Operating Expenses
Cost of sales	81,693			79,527			197,127			191,918
Operating, general and administrative	72,579			61,720			152,440			142,843
Property and other taxes	35,208			32,454			70,629			65,241
Depreciation and depletion	39,898			35,727			79,788			71,546
Total Operating Expenses	229,378			209,428			499,984			471,548
Operating Income	63,742			61,132			125,675			145,023
Interest Expense, net	(26,421		)	(22,943		)	(50,930		)	(46,058		)
Other Income	1,195			995			4,297			1,660
Income Before Income Taxes	38,516			39,184			79,042			100,625
Income Tax Expense	(2,947		)	(8,211		)	(5,419		)	(18,227		)
Net Income	$	35,569		$	30,973		$	73,623		$	82,398

Average Common Shares Outstanding	48,309			47,044			48,275			47,011
Basic Earnings per Average Common Share	$	0.74		$	0.66		$	1.53		$	1.75
Diluted Earnings per Average Common Share	$	0.73		$	0.65		$	1.52		$	1.74
Dividends Declared per Common Share	$	0.50		$	0.48		$	1.00		$	0.96

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)



	Three Months Ended June 30,					Six Months Ended June 30,
	2016		2015			2016			2015
Net Income	$	35,569	$	30,973		$	73,623		$	82,398
Other comprehensive income (loss), net of tax:
Foreign currency translation	8		(56		)	(110		)	212
Cash flow hedges:
Reclassification of net losses (gains) on derivative instruments	37		(91		)	74			(180		)
Total Other Comprehensive Income (Loss)	45		(147		)	(36		)	32
Comprehensive Income	$	35,614	$	30,826		$	73,587		$	82,430

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)



	June 30, 2016			December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	8,969		$	11,980
Restricted cash	6,588			6,634
Accounts receivable, net	115,833			154,410
Inventories	49,923			53,458
Regulatory assets	40,483			51,348
Other	16,195			8,830
Total current assets	237,991			286,660
Property, plant, and equipment, net	4,109,730			4,059,499
Goodwill	357,586			357,586
Regulatory assets	556,910			517,223
Other noncurrent assets	45,389			43,727
Total Assets	$	5,307,606		$	5,264,695
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,905		$	1,837
Short-term borrowings	256,806			229,874
Accounts payable	55,470			74,511
Accrued expenses	181,119			183,988
Regulatory liabilities	25,376			80,990
Total current liabilities	520,676			571,200
Long-term capital leases	25,373			26,325
Long-term debt	1,773,714			1,768,183
Deferred income taxes	553,824			501,532
Noncurrent regulatory liabilities	388,012			378,711
Other noncurrent liabilities	418,372			418,570
Total Liabilities	3,679,971			3,664,521
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,014 and 48,311,079 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	520			518
Treasury stock at cost	(96,265		)	(93,948		)
Paid-in capital	1,380,345			1,376,291
Retained earnings	351,667			325,909
Accumulated other comprehensive loss	(8,632		)	(8,596		)
Total Shareholders' Equity	1,627,635			1,600,174
Total Liabilities and Shareholders' Equity	$	5,307,606		$	5,264,695

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Six Months Ended June 30,
	2016			2015
OPERATING ACTIVITIES:
Net income	$	73,623		$	82,398
Items not affecting cash:
Depreciation and depletion	79,788			71,546
Amortization of debt issue costs, discount and deferred hedge gain	1,987			562
Stock-based compensation costs	3,361			2,331
Equity portion of allowance for funds used during construction	(1,608		)	(3,971		)
Loss (gain) on disposition of assets	1,054			(87		)
Deferred income taxes	5,535			19,919
Changes in current assets and liabilities:
Restricted cash	46			(12		)
Accounts receivable	38,577			40,591
Inventories	3,535			4,032
Other current assets	(7,365		)	(1,040		)
Accounts payable	(17,595		)	(30,186		)
Accrued expenses	786			(30,881		)
Regulatory assets	10,865			20,579
Regulatory liabilities	(55,614		)	4,389
Other noncurrent assets	(3,099		)	(1,014		)
Other noncurrent liabilities	7,118			11,182
Cash Provided by Operating Activities	140,994			190,338
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(121,246		)	(131,170		)
Acquisitions	—			(492		)
Proceeds from sale of assets	137			80
Change in restricted cash	—			9,153
Cash Used in Investing Activities	(121,109		)	(122,429		)
FINANCING ACTIVITIES:
Treasury stock activity	(1,614		)	(1,008		)
Dividends on common stock	(47,865		)	(44,760		)
Issuance of long-term debt	60,000			200,000
Repayments on long-term debt	(55,000		)	(150,016		)
Issuances (repayments) of short-term borrowings, net	26,932			(47,931		)
Financing costs	(5,349		)	(11,688		)
Cash Used in Financing Activities	(22,896		)	(55,403		)
(Decrease) Increase in Cash and Cash Equivalents	(3,011		)	12,506
Cash and Cash Equivalents, beginning of period	11,980			20,362
Cash and Cash Equivalents, end of period	$	8,969		$	32,868
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(2,922	)	$	27
Interest	42,861			44,611
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	11,054			9,199

See Notes to Condensed Consolidated Financial Statements

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

(Unaudited)

(in thousands, except per share data)



	Number of Common Shares	Number of Treasury Shares	Common Stock		Paid in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance at December 31, 2014	50,522	3,607	$	505	$	1,313,844		$	(92,558	)	$	264,758		$	(8,766	)	$	1,477,783

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

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

Net income	—	—	—		—			—			73,623			—			73,623
Foreign currency translation adjustment	—	—	—		—			—			—			(110		)	(110		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—			—			—			74			74
Stock-based compensation	167	28	—		4,065			(2,317		)	—			—			1,748
Issuance of shares	—	—	2		(11		)	—			—			—			(9		)
Dividends on common stock ($1.00 per share)	—	—	—		—			—			(47,865		)	—			(47,865		)
Balance at June 30, 2016	51,956	3,645	$	520	$	1,380,345		$	(96,265	)	$	351,667		$	(8,632	)	$	1,627,635

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 701,000 customers in Montana, South Dakota and Nebraska.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to June 30, 2016, have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Variable Interest Entities

A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.

Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain Qualifying Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 Megawatt (MW) coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per Megawatt Hour (MWH) (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $259.5 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 FASB delayed the effective date of this guidance to the first quarter of 2018, with early adoption permitted as of the original effective date of the first quarter of 2017. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures.

In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us in our first quarter of 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of adoption of this guidance, and based on our initial analysis do not expect it to have a significant impact on our Financial Statements and disclosures.

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

Accounting Standards Adopted

In February 2015, the FASB issued consolidation guidance that eliminated two consolidation models and requires all legal

entities to be evaluated under a voting interest entity model or a variable interest entity model. Both models require the reporting entity to identify whether it has a controlling financial interest in a legal entity and is therefore required to consolidate the entity. We adopted this guidance during the first quarter of 2016 with no material impact to our Financial Statements and disclosures.

In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, but adjustments to the carrying cost of debt. During the first quarter of 2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million and $13.0 million in the Condensed Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

(3) Regulatory Matters

Montana Electric and Natural Gas Tracker Filings

Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The Montana Public Service Commission (MPSC) reviews such filings and makes its cost recovery determination based on whether or not our supply procurement activities were prudent.

During the second quarter of 2016, we filed our 2016 annual electric and natural gas tracker filings for the 2015/2016 tracker period. We received orders from the MPSC in July 2016 approving the filings on an interim basis.

Electric Trackers - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - The MPSC held a work session in March 2016 and directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs in each of the periods. On the same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work sessions, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million, which included $8.2 million of replacement power costs and $2.1 million of modeling costs.

In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. We filed a motion for reconsideration of the decision with the MPSC regarding the disallowance of portfolio modeling costs, which was denied. In June 2016, we filed an appeal of the decision in Montana District Court.

In May 2016, we received the final written order in the Consolidated Docket. The written order clarified the disallowance of modeling costs, resulting in a reduction of the disallowance recorded during the first quarter of 2016 of $0.8 million, which is reflected as a reduction in cost of sales in the Condensed Consolidated Statement of Income for the three months ended June 30, 2016.

In addition, the May 2016 Consolidated Docket final order upheld the March 2016 decision regarding replacement power costs, concluding that we were imprudent by failing to (1) mitigate a risk by not investigating outage insurance; (2) investigate alternative recovery mechanisms prior to seeking recovery from customers; and (3) meet our burden of proof because the filing lacked sufficient information demonstrating the prudency of the replacement power costs. We filed a motion for reconsideration of the decision with the MPSC. The matter is fully briefed and awaiting a decision by the MPSC.

Electric and Natural Gas Lost Revenue Adjustment Mechanism - In 2005, the MPSC approved an energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in kilowatt hour sales lost due to the implementation of energy saving measures. In an order issued in October 2013 related to our 2011/2012 electric supply tracker, the MPSC required us to lower the calculated lost revenue recovery and imposed a new burden of proof on us for future recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In October 2015, the MPSC issued an order to eliminate the lost revenue adjustment mechanism prospectively effective December 1, 2015.

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

Hydro Compliance Filing

In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A procedural schedule has been established and a hearing is scheduled for September 2016. We expect the MPSC to issue a final order during the fourth quarter of 2016. Due to the timing of the rate adjustment, as of June 30, 2016, we have deferred revenue of approximately $4.9 million that we expect to refund to customers in 2016.

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

In May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had deferred cumulative revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit. The briefing schedule for this appeal has not been established.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of June 30, 2016, the DGGS net property, plant and equipment is approximately $152 million. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change.

(4) Income Taxes

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



	Three Months Ended June 30,
	2016					2015
Income Before Income Taxes	$	38,516				$	39,184

Income tax calculated at 35% federal statutory rate	13,481			35.0	%	13,715			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(1,025		)	(2.7	)	367			0.9
Flow-through repairs deductions	(6,971		)	(18.1	)	(4,848		)	(12.4	)
Production tax credits	(2,324		)	(6.0	)	(651		)	(1.7	)
Plant and depreciation of flow through items	(246		)	(0.6	)	(245		)	(0.6	)
Prior year permanent return to accrual adjustments	(128		)	(0.3	)	—			—
Other, net	160			0.4		(127		)	(0.2	)
	(10,534		)	(27.3	)	(5,504		)	(14.0	)

Income Tax Expense	$	2,947		7.7	%	$	8,211		21.0	%



	Six Months Ended June 30,
	2016					2015
Income Before Income Taxes	$	79,042				$	100,625

Income tax calculated at 35% federal statutory rate	27,665			35.0	%	35,219			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(2,125		)	(2.6	)	528			0.6
Flow-through repairs deductions	(13,645		)	(17.3	)	(14,461		)	(14.4	)
Production tax credits	(5,099		)	(6.5	)	(1,912		)	(1.9	)
Plant and depreciation of flow through items	(1,184		)	(1.5	)	(626		)	(0.6	)
Prior year permanent return to accrual adjustments	(128		)	(0.2	)	—			—
Other, net	(65		)	—		(521		)	(0.6	)
	(22,246		)	(28.1	)	(16,992		)	(16.9	)

Income Tax Expense	$	5,419		6.9	%	$	18,227		18.1	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $91.0 million as of June 30, 2016, including approximately $66.8 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the six months ended June 30, 2016 we recognized $0.3 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of June 30, 2016, we had $0.3 million of interest accrued in the Condensed Consolidated Balance Sheets. During the six months ended June 30, 2015, we did not recognize any expense for interest or penalties, and did not have any amounts accrued as of December 31, 2015, for the payment of interest and penalties.

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

(5) Goodwill

We completed our annual goodwill impairment test as of April 1, 2016, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.

There were no changes in our goodwill during the six months ended June 30, 2016. Goodwill by segment is as follows for both June 30, 2016 and December 31, 2015 (in thousands):



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

(6) Comprehensive Income (Loss)

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



	Three Months Ended
	June 30, 2016							June 30, 2015
	Before-Tax Amount		Tax Expense			Net-of-Tax Amount		Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	8	$	—		$	8	$	(56	)	$	—	$	(56	)
Reclassification of net losses (gains) on derivative instruments	62		(25		)	37		(143		)	52		(91		)
Other comprehensive income (loss)	$	70	$	(25	)	$	45	$	(199	)	$	52	$	(147	)



	Six Months Ended
	June 30, 2016									June 30, 2015
	Before-Tax Amount			Tax Expense			Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(110	)	$	—		$	(110	)	$	212		$	—	$	212
Reclassification of net losses (gains) on derivative instruments	124			(50		)	74			(286		)	106		(180		)
Other comprehensive income (loss)	$	14		$	(50	)	$	(36	)	$	(74	)	$	106	$	32

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



	June 30, 2016			December 31, 2015
Foreign currency translation	$	1,245		$	1,355
Derivative instruments designated as cash flow hedges	(8,940		)	(9,014		)
Pension and postretirement medical plans	(937		)	(937		)
Accumulated other comprehensive loss	$	(8,632	)	$	(8,596	)

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



		Three Months Ended
		June 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,977	)	$	(937	)	$	1,237	(8,677		)
Other comprehensive income before reclassifications		—			—			8		8
Amounts reclassified from AOCL	Interest Expense	37			—			—		37
Net current-period other comprehensive income		37			—			8		45
Ending balance		$	(8,940	)	$	(937	)	$	1,245	$	(8,632	)



		Three Months Ended
		June 30, 2015
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(8,405	)	$	(1,247	)	$	1,065		(8,587		)
Other comprehensive loss before reclassifications		—			—			(56		)	(56		)
Amounts reclassified from Accumulated Other Comprehensive Income (AOCI)	Interest Expense	(91		)	—			—			(91		)
Net current-period other comprehensive loss		(91		)	—			(56		)	(147		)
Ending balance		$	(8,496	)	$	(1,247	)	$	1,009		$	(8,734	)



		Six Months Ended
		June 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	$	(937	)	$	1,355		(8,596		)
Other comprehensive loss before reclassifications		—			—			(110		)	(110		)
Amounts reclassified from AOCL	Interest Expense	74			—			—			74
Net current-period other comprehensive income (loss)		74			—			(110		)	(36		)
Ending balance		$	(8,940	)	$	(937	)	$	1,245		$	(8,632	)



		Six Months Ended
		June 30, 2015
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,316	)	$	(1,247	)	$	797	(8,766		)
Other comprehensive income before reclassifications		—			—			212		212
Amounts reclassified from AOCI	Interest Expense	(180		)	—			—		(180		)
Net current-period other comprehensive (loss) income		(180		)	—			212		32
Ending balance		$	(8,496	)	$	(1,247	)	$	1,009	$	(8,734	)

(7) Risk Management and Hedging Activities

Nature of Our Business and Associated Risks

We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

Objectives and Strategies for Using Derivatives

To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines.

In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.

Accounting for Derivative Instruments

We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Financial Statements at June 30, 2016 and December 31, 2015. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Credit Risk

Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.

We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric

contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

Interest Rate Swaps Designated as Cash Flow Hedges

We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

A net pre-tax loss of approximately $14.8 million is remaining in AOCL as of June 30, 2016, and we expect to reclassify approximately $0.3 million of net pre-tax gains from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

(8) Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:


•	Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;


•	Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and


•	Level 3 – Significant inputs that are generally not observable from market activity.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 - Risk Management and Hedging Activities for further discussion.

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



	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
June 30, 2016
Restricted cash	$	6,232	$	—	$	—	$	—	$	6,232
Rabbi trust investments	27,121		—		—		—		27,121
Total	$	33,353	$	—	$	—	$	—	$	33,353

December 31, 2015
Restricted cash	$	6,240	$	—	$	—	$	—	$	6,240
Rabbi trust investments	24,245		—		—		—		24,245
Total	$	30,485	$	—	$	—	$	—	$	30,485

Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets.

Financial Instruments

The estimated fair value of financial instruments is summarized as follows (in thousands):



	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,773,714	$	1,976,889	$	1,768,183	$	1,844,974

Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.

We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

(9) Financing Activities

In June 2016, we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026. These bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018.

(10) Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs.

We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions.

Financial data for the business segments are as follows (in thousands):



Three Months Ended
June 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	248,403		$	44,717		$	—		$	—	$	293,120
Cost of sales	72,165			9,528			—			—		81,693
Gross margin	176,238			35,189			—			—		211,427
Operating, general and administrative	51,568			20,585			426			—		72,579
Property and other taxes	27,322			7,883			3			—		35,208
Depreciation and depletion	32,544			7,346			8			—		39,898
Operating income (loss)	64,804			(625		)	(437		)	—		63,742
Interest expense	(24,119		)	(1,814		)	(488		)	—		(26,421		)
Other income	687			271			237			—		1,195
Income tax (expense) benefit	(3,331		)	1,278			(894		)	—		(2,947		)
Net income (loss)	$	38,041		$	(890	)	$	(1,582	)	$	—	$	35,569
Total assets	$	4,221,293		$	1,080,065		$	6,248		—		$	5,307,606
Capital expenditures	$	57,938		$	11,990		$	—		—		$	69,928



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



Six Months Ended
June 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	489,745		$	135,914		$	—		$	—	$	625,659
Cost of sales	155,789			41,338			—			—		197,127
Gross margin	333,956			94,576			—			—		428,532
Operating, general and administrative	107,011			42,497			2,932			—		152,440
Property and other taxes	54,751			15,872			6			—		70,629
Depreciation and depletion	65,065			14,707			16			—		79,788
Operating income (loss)	107,129			21,500			(2,954		)	—		125,675
Interest expense	(46,174		)	(3,769		)	(987		)	—		(50,930		)
Other income	1,154			580			2,563			—		4,297
Income tax (expense) benefit	(4,346		)	(1,743		)	670			—		(5,419		)
Net income (loss)	$	57,763		$	16,568		$	(708	)	$	—	$	73,623
Total assets	$	4,221,293		$	1,080,065		$	6,248		—		$	5,307,606
Capital expenditures	$	99,563		$	21,683		$	—		—		$	121,246



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

(11) Earnings Per Share

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



	Three Months Ended
	June 30, 2016	June 30, 2015
Basic computation	48,308,656	47,043,735
Dilutive effect of:
Performance share awards (1)	66,787	243,961

Diluted computation	48,375,443	47,287,696



	Six Months Ended
	June 30, 2016	June 30, 2015
Basic computation	48,275,482	47,010,546
Dilutive effect of:
Performance share awards (1)	66,621	247,696

Diluted computation	48,342,103	47,258,242

______________

(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.

(12) Employee Benefit Plans

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



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	$	2,941		$	2,718		$	116		$	134
Interest cost	6,539			6,545			196			210
Expected return on plan assets	(7,043		)	(7,861		)	(260		)	(242		)
Amortization of prior service cost	61			61			(470		)	(441		)
Recognized actuarial loss	2,478			2,699			71			112
Net Periodic Benefit Cost (Income)	$	4,976		$	4,162		$	(347	)	$	(227	)



	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	5,880			$	6,181		$	246		$	263
Interest cost	13,105			13,087			398			393
Expected return on plan assets	(14,124		)	(15,781		)	(521		)	(485		)
Amortization of prior service cost	123			123			(941		)	(941		)
Recognized actuarial loss	4,944			5,317			158			193
Net Periodic Benefit Cost (Income)	$	9,928		$	8,927		$	(660	)	$	(577	)

(13) Commitments and Contingencies



ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us and is estimated to range between $27 million to $32 million. As of June 30, 2016, we have a reserve of approximately $30.9 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately $24.3 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. As of June 30, 2016, the reserve for remediation costs at this site is approximately $11.4 million, and we estimate that approximately $6.7 million of this amount will be incurred during the next five years.

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

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana's state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. In 2016, the MDEQ requested additional information regarding the Helena site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte and Helena sites.

An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District, a draft risk assessment was prepared for the Missoula site and presented to the Missoula County Water Quality Board (MCWQB). The MCWQB deferred all decision making to the MDEQ, but suggested additional site delineation. Additional delineation work began in December 2015 and has continued in 2016. The result of the additional delineation work may lead to amending the risk assessment and/or development of a remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Missoula 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 (CO2). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions.

On August 3, 2015, the EPA released for publication in the Federal Register, the final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed natural gas combined cycle (NGCC) units. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit.

In a separate action that also affects power plants, on August 3, 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) (the Clean Power Plan, or CPP). The CPP establishes CO₂ emission performance standards for existing electric utility steam generating units and NGCC units. States may develop implementation plans for affected units to meet the individual state targets established in the CPP or may adopt a federal plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour (MWH)) or mass-based tonnage limits for CO₂. The 2030 rate-based requirement for all existing affected generating units in South Dakota and Montana is 1,167 and 1,305 pounds per MWH, respectively. The rate-based approach requires a 38.4 percent reduction in South Dakota and a 47.4 percent reduction in Montana from 2012 levels by 2030. The mass-based approach for existing units in South Dakota requires a 30.9 percent decrease by 2030, while in Montana the mass-based approach requires a 41 percent decrease by 2030. States are required to submit initial plans for achieving GHG emission standards to EPA by September 2016, but may seek additional time to finalize State plans by September 2018. The initial performance period for compliance would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program that would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program that would allow trading of allowances with an allowance equal to one short ton of CO₂; and a state measures program that would allow intra-state trading to achieve the state-wide average emission rate.

On August 3, 2015, the EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one

of the two options. The EPA has indicated that it intends to finalize both the federal plan and the model trading rules in the summer of 2016.

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

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

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

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

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

We are evaluating the implications of these rules and technology available to achieve the CO₂ emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters or what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure

related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the Second Circuit Court of Appeals.

In November 2015, the EPA published final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. The rule became effective in January 2016. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations. Challenges to the final rule have been filed in the Fifth Circuit Court of Appeals, indicating that the EPA underestimated compliance costs. It is too early to determine whether the impacts of these rules will be material.

Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership.

In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit Court in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit, and the D.C. Circuit remanded, without vacatur, the MATS rule to the EPA, leaving the rule in place. In April 2016, the EPA published its final supplemental finding that it is "appropriate and necessary" to regulate coal and oil-fired units under Section 112 of the Clean Air Act. Although industry and trade associations have filed a lawsuit in the D.C. Circuit challenging the EPA's supplemental finding, installation or upgrading of relevant environmental controls at our affected plants is complete and we are controlling emissions of mercury under the state and Federal MATS rules.

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

In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.

The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in 'Class I' areas.

In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Units 3 and 4 do not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana (now Talen Montana), the operator of Colstrip, as well as environmental groups (National Parks Conservation

Association, Montana Environmental Information Center, and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center (MEIC) and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, the U.S. Court of Appeals for the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. Each state is required by the CPP to submit a satisfactory plan to EPA by September 2018. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us. In addition, compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in January 2016, is not expected to have a significant impact at any of our jointly owned facilities.

North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx emissions by July 2018. Coyote is in the process of installing 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, with the project expected to be operational in the third quarter of 2016. The cost of the control equipment is not significant.

Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's coal combustion residual rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90.0 million (our share is 30%) over the remaining life of the facility.

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

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:


•	We may not know all sites for which we are alleged or will be found to be responsible for remediation; and


•	Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

Colstrip Litigation

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

On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief that dropped claims associated with projects completed before 2001, Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects.

In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO2, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits.

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

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

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

On December 1, 2015, the Court held oral argument on all pending motions for summary judgment, and on December 31, 2015, the Magistrate issued findings and recommendations which (a) denied Plaintiffs’ motion for partial summary judgment regarding routine maintenance, repair and replacement; (b) denied Plaintiffs’ motion for partial summary judgment that the redesign projects for the Unit 1 and 4 turbines and the Unit 1 economizer were not “like kind replacements” (c) granted Defendants’ motion for partial summary judgment regarding Plaintiffs’ use of the “actual-to-potential” emissions test; (d) granted in part and denied in part Plaintiffs’ motion for partial summary judgment regarding the allowable period from which to select a baseline for the Unit 3 reheater project; (e) granted in part and denied in part Defendants’ motion for partial summary judgment on baseline selection; and (f) granted Defendants’ motion for partial summary judgment on emissions calculations for alleged aggregated turbine and safety valve project. Plaintiffs filed objections to the Magistrate’s findings and recommendations on January 19, 2016, and Defendants filed their response on February 5, 2016.

The Court has not ruled on the Magistrate’s proposed findings and recommendations and the matter was scheduled to go to a bench trial on May 31, 2016. However, on April 26, 2016, the parties filed a joint motion to vacate the May 31, 2016, trial date and to stay all deadlines, to allow the parties to settle the litigation.

The parties lodged a proposed consent decree with the Court on July 12, 2016. The consent decree would dismiss all of the claims against all units, including Colstrip Unit 4, the only unit in which we have an ownership interest, and provides no shut-down date for Units 3 and 4. On the other hand, the consent decree provides that Units 1 and 2 must be shut down by July 1, 2022. Units 1 and 2 are owned solely by Talen and Puget Sound Energy. We had no role in the decisions regarding Units 1 and 2 as we have no ownership interest in those units.

If the Court enters the consent decree, all claims raised by plaintiffs against all four Colstrip units will be resolved. The EPA and the Department of Justice (DOJ) have 45 days from July 12, 2016, to comment on the consent decree or intervene of right. Following the 45-day period, the parties will seek approval and entry of the consent decree or will take other appropriate actions should there be any material comments on the consent decree by the United States or if the United States intervenes. The consent decree permits parties to petition the Court for costs and attorneys’ fees within 30 days after the Court enters the consent decree. We intend to seek attorneys’ fees and costs from the Sierra Club and the MEIC.

The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facility agreement among the owners of all four units. If Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. However, we do not anticipate that this increase will be material to our financial results.

In the event the Court does not enter the consent decree, we intend to continue to vigorously defend this lawsuit and cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision.

Billings, Montana Refinery Outage Claim

In August 2014, we received a letter from the ExxonMobil refinery in Billings claiming that it had sustained approximately $48.5 million in damages as a result of a January 2014 electrical outage. In December 2015, Exxon increased the estimated losses related to that incident to approximately $61.7 million. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. We dispute ExxonMobil’s claims and intend to vigorously defend this lawsuit. We have reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also have brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they are responsible in whole or in part for the outages. This matter is in the initial stages and we cannot predict an outcome or estimate the amount or range of loss that would be associated with an adverse result.

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana filed a complaint on remand with the Montana First Judicial District Court (State District Court), naming us, along with Talen Montana, LLC (Talen), as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan and Morony facilities on the Missouri-Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

Prior to our acquisition of the facilities, Talen litigated this issue against the State in Montana state courts and in the United States Supreme Court. In August 2007, the State District Court determined that the 10 hydroelectric facilities were located on rivers which were navigable and that the State held title to the riverbeds. Subsequently, in June 2008, the District Court awarded the State compensation with respect to all 10 facilities of approximately $34 million for the 2000-2006 period and approximately $6 million for 2007 (we have owned the facilities since November 2014). The District Court deferred the determination of compensation for 2008 and future years to the Montana State Land Board.

Talen appealed the issue of navigability to the Montana Supreme Court, which in March 2010 affirmed the State District Court decision. In June 2011, Talen petitioned the United States Supreme Court to review the Montana Supreme Court decision. The United States Supreme Court issued an opinion in February 2012, overturning the Montana Supreme Court and holding that the Montana courts erred first by not considering the navigability of the rivers on a segment-by-segment basis and second in relying on present day recreational use of the rivers. The United States Supreme Court also considered the navigability of what it referred to as the Great Falls Reach and concluded, at least from the head of the first waterfall to the foot of the last, that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion.

Following the 2012 remand, the case laid dormant for four years until the State filed the complaint on remand with the State District Court. The complaint on remand renews all of the State’s claims that the rivers on which the 10 hydroelectric facilities are located are navigable (including the Great Falls Reach), and that because they were navigable the riverbeds became State lands upon Montana’s statehood in 1889 and that the State is entitled to rent for their use. The State’s complaint on remand does not claim any specific rental amount. Pursuant to the terms of our acquisition of the hydroelectric facilities, Talen and NorthWestern will share jointly the expense of this litigation, and Talen is responsible for any rents applicable to the periods of time prior to the acquisition (i.e., before November 18, 2014), while we are responsible for periods thereafter.

In April 2016, we removed the case from State District Court to the U.S. District Court for the District of Montana (Federal District Court), and Talen consented to such removal. In addition, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with the Great Falls Reach in light of the U.S. Supreme Court’s decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment.

In May 2016, the State asked the Federal District Court to remand the case back to the State District Court and to dismiss Talen’s consent to removal. We filed a brief in opposition to the State’s motion to remand, and Talen filed a joinder to our brief, and we and Talen filed oppositions to the State’s motion to dismiss Talen’s consent to removal. The State filed its replies in July

2016. Following the State's replies, we filed a request for oral argument and/or surreply. All of the motions (ours and the State’s) and our request remain pending before the Federal District Court.

We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If the Federal District Court (or State District Court if the case is remanded back to it) determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as before remand, we estimate the annual rents could be approximately $7.0 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 701,000 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2015.

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



HOW WE PERFORMED AGAINST OUR SECOND QUARTER 2015 RESULTS



	Quarter-over-Quarter Change

Gross Margin by Segment⁽¹⁾
Electric	$20.7M	é	13.3%
Natural Gas	$(0.4)M	ê	(1.1)%


Operating Income	$2.6M	é	4.3%


Net Income	$4.6M	é	14.8%


EPS (Diluted)	$0.08	é	12.3%

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



SIGNIFICANT DEVELOPMENTS IN Q2 2016



	Ÿ	An increase in Net Income of $4.6 million, primarily due to improved gross margin, driven by the recognition of deferred revenue upon receipt of an MPSC final order and an increase in South Dakota electric rates, and lower income tax expense. These improvements were partially offset by the inclusion of a $20.8 million recovery of environmental related costs in our second quarter of 2015 as a reduction of operating costs.

	Ÿ	Issuance of $60 million of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026, to refinance our 6.05%, $55 million First Mortgage Bonds due 2018.

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



SIGNIFICANT TRENDS AND REGULATION

Rate Cases

General rate cases are necessary to cover the costs of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We evaluate the need for electric and natural gas rate changes in each of our jurisdictions annually. We are required to make a filing by the end of September 2016 to address the cost-recovery of our gas production fields that are being collected through the natural gas tracker on an interim basis. In addition, we expect to submit a natural gas delivery and production rate filing based on a 2015 test year at the same time.

Montana Electric and Natural Gas Tracker Filings

Electric Tracker - The MPSC held a work session in March 2016 and directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs. On the same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work session, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million, which included $8.2 million of replacement power costs and $2.1 million of modeling costs.


•	Based on the final order, the impact of the disallowance during the six months ended June 30, 2016 totals $12.4 million, which includes interest of $2.9 million.

In addition, the May 2016 Consolidated Docket final order upheld the March 2016 decision regarding replacement power costs concluding that we were imprudent by failing to (1) mitigate a risk by not investigating outage insurance; (2) investigate alternative recovery mechanisms prior to seeking recovery from customers; and (3) meet our burden of proof because the filing lacked sufficient information demonstrating the prudency of the replacement power costs. We filed a motion for reconsideration of the decision with the MPSC. The matter is fully briefed and awaiting a decision by the MPSC.

Electric and Natural Gas Lost Revenue Adjustment Mechanism - In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 by the MPSC as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in the kWh sales lost due to energy efficiency programs through our electric and natural supply tracker. Lost revenues were removed prospectively effective December 1, 2015.

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


•	We recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the three months ended June 30, 2016 based on the final orders in our tracker filings.

Hydro Compliance Filing

The MPSC order approving our acquisition of the hydro assets provided that customers would have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes (CSKT). We sold any excess system generation, which was primarily due to our temporary ownership of Kerr, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. Therefore, during our temporary ownership a net benefit of approximately $2.7 million was provided to customers and there was no benefit to shareholders. In December 2015, we submitted the required compliance filing to remove Kerr from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro generation rate based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of Kerr. The MPSC identified additional issues and requested information. A procedural schedule has been established and a hearing is scheduled for September 2016. We expect the MPSC to issue a final order during the fourth quarter of 2016.


•	We expect the reduction in revenues as a result of the conveyance of Kerr to be offset with a corresponding reduction in operating expenses.

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

In June 2016, we filed a petition for review of the FERC's May 2016 order with the U.S. Circuit Court of Appeals for the District of Columbia Circuit. The briefing schedule for this appeal has not been established.

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

Montana Electricity Supply Resource Procurement Plan

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

Supply Investments

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



RESULTS OF OPERATIONS

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

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation and depletion from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, 2016 Compared with the Three Months Ended June 30, 2015



	Three Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	248.4	$	221.4	$	27.0		12.2	%
Natural Gas	44.7		49.2		(4.5		)	(9.1	)
Total Operating Revenues	$	293.1	$	270.6	$	22.5		8.3	%



	Three Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	72.2	$	65.9	$	6.3		9.6	%
Natural Gas	9.5		13.6		(4.1		)	(30.1	)
Total Cost of Sales	$	81.7	$	79.5	$	2.2		2.8	%



	Three Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	176.2	$	155.5	$	20.7		13.3	%
Natural Gas	35.2		35.6		(0.4		)	(1.1	)
Total Gross Margin	$	211.4	$	191.1	$	20.3		10.6	%

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



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Lost revenue adjustment mechanism	$	12.6
South Dakota electric rate increase	10.0
Electric QF adjustment	6.1
Natural gas production	0.9
MPSC disallowance (adjustment)	0.8
Electric retail volumes	0.3
Natural gas retail volumes	(1.3		)
Electric transmission	(0.7		)
Other	(1.4		)
Change in Gross Margin Impacting Net Income	27.3

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(5.9		)
Production tax credits flowed-through trackers	(2.7		)
Gas production gathering fees	(0.6		)
Property taxes recovered in trackers	2.2
Change in Items Offset Within Net Income	(7.0		)
Increase in Consolidated Gross Margin	$	20.3

Consolidated gross margin for items impacting net income increased $27.3 million, due to the following:


•	The recognition of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings, which was offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $1.6 million in the second quarter of 2016;


•	An increase in South Dakota electric rates;


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


•	An increase in natural gas production revenue due to a change in interim rates based on actual costs;


•	An adjustment in the disallowance of modeling costs based on the MPSC final order, as discussed above; and


•	An increase in electric residential and commercial volumes due primarily to customer growth. Warmer spring weather in South Dakota was offset by unfavorable weather in Montana. These increases were partly offset by


•	A decrease in natural gas retail volumes due primarily to warmer spring weather, partly offset by customer growth; and


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

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


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


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


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


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



	Three Months Ended June 30,
	2016		2015		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	72.6	$	61.7	$	10.9	17.7	%
Property and other taxes	35.2		32.5		2.7		8.3
Depreciation and depletion	39.9		35.7		4.2		11.8
	$	147.7	$	129.9	$	17.8	13.7	%

Consolidated operating, general and administrative expenses were $72.6 million for the three months ended June 30, 2016, as compared with $61.7 million for the three months ended June 30, 2015. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2016 vs. 2015
	(in millions)
Insurance recovery, net	$	20.8
Non-employee directors deferred compensation	1.6
Hydro operations - Kerr conveyance	(5.6		)
Distribution System Infrastructure Project (DSIP) expenses	(1.3		)
Bad debt expense	(1.2		)
Gas production gathering expense	(0.6		)
Other	(2.8		)
Increase in Operating, General & Administrative Expenses	$	10.9

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


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


•	The change in value of non-employee directors deferred compensation due to changes in our stock price (offset by changes in other income with no impact on net income).

These increases were offset in part by:


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


•	Lower DSIP related expenses;


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


•	A decrease in natural gas gathering expense (offset by lower gathering fees discussed above); and


•	Cost control measures implemented in 2016, which are included in Other.

Property and other taxes were $35.2 million for the three months ended June 30, 2016, as compared with $32.5 million in the same period of 2015. This increase was primarily due to plant additions and higher estimated property valuations in Montana, offset in part by a $0.3 million decrease from the conveyance of Kerr to the CSKT in September 2015. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November. In addition, under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and recover these amounts. The MPSC has authorized recovery of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) as compared to the related amount included in rates during our last general rate case.

Depreciation and depletion expense was $39.9 million for the three months ended June 30, 2016, as compared with $35.7 million in the same period of 2015. This increase was primarily due to plant additions, including approximately $1.4 million of depreciation associated with the Beethoven wind project acquisition.

Consolidated operating income for the three months ended June 30, 2016 was $63.7 million, as compared with $61.1 million in the same period of 2015. This increase was primarily due to the increase in gross margin offset in part by higher operating costs as discussed above.

Consolidated interest expense for the three months ended June 30, 2016 was $26.4 million, as compared with $22.9 million in the same period of 2015. This increase was primarily due to $2.9 million of interest associated with the MPSC disallowance as discussed above, increased debt outstanding associated with the September 2015 Beethoven wind project acquisition, and lower capitalization of allowance for funds used during construction (AFUDC).

Consolidated other income for the three months ended June 30, 2016, was $1.2 million, as compared with $1.0 million in the same period of 2015. This increase was primarily due to a $1.6 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding increase to operating, general and administrative expenses). This is partially offset by lower capitalization of AFUDC.

Consolidated income tax expense for the three months ended June 30, 2016 was $2.9 million, as compared with $8.2 million in the same period of 2015. Our effective tax rate for the three months ended June 30, 2016 was 7.7% as compared with 21.0% for the same period of 2015. We currently expect our 2016 effective tax rate to range between 6% - 10%.

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



	Three Months Ended June 30,
	2016					2015
Income Before Income Taxes	$	38.5				$	39.2

Income tax calculated at 35% federal statutory rate	13.5			35.0	%	13.7			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(1.0		)	(2.7	)	0.4			0.9
Flow-through repairs deductions	(7.0		)	(18.1	)	(4.9		)	(12.4	)
Production tax credits	(2.3		)	(6.0	)	(0.7		)	(1.7	)
Plant and depreciation of flow through items	(0.3		)	(0.6	)	(0.2		)	(0.6	)
Prior year permanent return to accrual adjustments	(0.1		)	(0.3	)	—			—
Other, net	0.1			0.4		(0.1		)	(0.2	)
	(10.6		)	(27.3	)	(5.5		)	(14.0	)

Income Tax Expense	$	2.9		7.7	%	$	8.2		21.0	%

Consolidated net income for the three months ended June 30, 2016 was $35.6 million as compared with $31.0 million for the same period in 2015. This increase was primarily due to improved gross margin, due to the recognition of deferred revenue and the South Dakota electric rate increase, and lower income tax expense, partly offset by higher operating expenses due to the insurance recovery included in our 2015 results and higher interest expense.

Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015



	Six Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	489.7	$	457.4	$	32.3		7.1	%
Natural Gas	135.9		159.2		(23.3		)	(14.6	)
Total Operating Revenues	$	625.6	$	616.6	$	9.0		1.5	%



	Six Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	155.8	$	129.8	$	26.0		20.0	%
Natural Gas	41.3		62.1		(20.8		)	(33.5	)
Total Cost of Sales	$	197.1	$	191.9	$	5.2		2.7	%



	Six Months Ended June 30,
	2016		2015		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	333.9	$	327.6	$	6.3		1.9	%
Natural Gas	94.6		97.1		(2.5		)	(2.6	)
Total Gross Margin	$	428.5	$	424.7	$	3.8		0.9	%

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



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota electric rate increase	$	18.6
Lost revenue adjustment mechanism	10.6
Electric QF adjustment	6.1
MPSC disallowance	(9.5		)
Electric transmission	(2.0		)
Natural gas retail volumes	(1.1		)
Natural gas production	(0.7		)
Electric retail volumes	(0.7		)
Other	(2.7		)
Change in Gross Margin Impacting Net Income	18.6

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(11.8		)
Production tax credits flowed-through trackers	(5.9		)
Gas production gathering fees	(1.0		)
Property taxes recovered in trackers	3.9
Change in Items Offset Within Net Income	(14.8		)
Increase in Consolidated Gross Margin	$	3.8

Consolidated gross margin for items impacting net income increased $18.6 million, which includes the following:


•	An increase in South Dakota electric rates; and


•	The recognition of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings, offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $3.6 million in 2016; and


•	The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on a review of contract assumptions. These increases were partly offset by


•	The MPSC disallowance of previously incurred costs as discussed above;


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


•	A decrease in natural gas volumes due primarily to warmer spring weather, partly offset by customer growth;


•	A decrease in natural gas production margin due to a change in interim rates based on actual costs; and


•	A decrease in electric retail volumes due primarily to warmer winter weather and lower industrial volumes of a large Montana customer, partly offset by customer growth.

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


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


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


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


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



	Six Months Ended June 30,
	2016		2015		Change		% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	152.4	$	142.8	$	9.6	6.7	%
Property and other taxes	70.6		65.2		5.4		8.3
Depreciation and depletion	79.8		71.6		8.2		11.5
	$	302.8	$	279.6	$	23.2	8.3	%

Consolidated operating, general and administrative expenses were $152.4 million for the six months ended June 30, 2016, as compared with $142.8 million for the six months ended June 30, 2015. Primary components of the change include the following:



	Operating, General & Administrative Expenses
	2016 vs. 2015
	(in millions)
Insurance recovery, net	$	20.8
Non-employee directors deferred compensation	4.7
Insurance reserves	0.9
Hydro operations - Kerr conveyance	(11.2		)
Bad debt expense	(2.2		)
DSIP expenses	(1.6		)
Gathering expense	(1.0		)
Other	(0.8		)
Increase in Operating, General & Administrative Expenses	$	9.6

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


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


•	The change in value of non-employee directors deferred compensation due to changes in our stock price (offset by changes in other income with no impact on net income); and


•	An increase in insurance reserves primarily due to the Billings, Montana refinery outage discussed in Note 13 to the Financial Statements.

These increases were offset in part by:


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


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


•	Lower DSIP related expenses;


•	A decrease in natural gas gathering expense (offset by lower gathering fees discussed above); and


•	Cost control measures implemented in 2016, which are included in Other.

Property and other taxes were $70.6 million for the six months ended June 30, 2016, as compared with $65.2 million in the same period of 2015. This increase was primarily due to plant additions and higher estimated property valuations in Montana, offset in part by a $0.6 million decrease from the conveyance of Kerr to the CSKT in September 2015.

Depreciation and depletion expense was $79.8 million for the six months ended June 30, 2016, as compared with $71.6 million in the same period of 2015. This increase was primarily due to plant additions, including approximately $2.8 million of depreciation associated with the September 2015 Beethoven wind project acquisition.

Consolidated operating income for the six months ended June 30, 2016 was $125.7 million, as compared with $145.0 million in the same period of 2015. This decrease was primarily due to the $20.8 million insurance recovery in 2015, partly offset by higher gross margin as discussed above.

Consolidated interest expense for the six months ended June 30, 2016 was $50.9 million, as compared with $46.1 million in the same period of 2015. This increase was primarily due to $2.9 million of interest associated with the MPSC disallowance as discussed above, increased debt outstanding associated with the Beethoven wind project acquisition, and lower capitalization of allowance for funds used during construction (AFUDC).

Consolidated other income for the six months ended June 30, 2016, was $4.3 million, as compared with $1.7 million in the same period of 2015. This increase was primarily due to a $4.7 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding increase to operating, general and administrative expenses). This was partially offset by lower capitalization of AFUDC.

Consolidated income tax expense for the six months ended June 30, 2016 was $5.4 million, as compared with $18.2 million in the same period of 2015. Our effective tax rate for the six months ended June 30, 2016 was 6.9% as compared with 18.1% for the same period of 2015.

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



	Six Months Ended June 30,
	2016					2015
Income Before Income Taxes	$	79.0				$	100.6

Income tax calculated at 35% federal statutory rate	27.7			35.0	%	35.2			35.0	%

Permanent or flow through adjustments:
State income, net of federal provisions	(2.1		)	(2.6	)	0.5			0.6
Flow-through repairs deductions	(13.7		)	(17.3	)	(14.5		)	(14.4	)
Production tax credits	(5.1		)	(6.5	)	(1.9		)	(1.9	)
Plant and depreciation of flow through items	(1.2		)	(1.5	)	(0.6		)	(0.6	)
Prior year permanent return to accrual adjustments	(0.1		)	(0.2	)	—			—
Other, net	(0.1		)	—		(0.5		)	(0.6	)
	(22.3		)	(28.1	)	(17.0		)	(16.9	)

Income Tax Expense	$	5.4		6.9	%	$	18.2		18.1	%

Consolidated net income for the six months ended June 30, 2016 was $73.6 million as compared with $82.4 million for the same period in 2015. This decrease was primarily due to the inclusion in our 2015 results of a $20.8 million insurance recovery and higher interest expense, partly offset by higher other income and lower income tax expense.

ELECTRIC SEGMENT

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


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


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


•	Transmission: Reflects transmission revenues regulated by the FERC.


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

•

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

Three Months Ended June 30, 2016 Compared with the Three Months Ended June 30, 2015



	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	200.6	$	193.7	$	6.9		3.6	%
Regulatory amortization	16.1		11.6		4.5			38.8
Total retail revenues	216.7		205.3		11.4			5.6
Transmission	12.7		13.4		(0.7		)	(5.2	)
Ancillary services	0.4		0.4		—			—
Wholesale and other	18.6		2.3		16.3			708.7
Total Revenues	248.4		221.4		27.0			12.2
Total Cost of Sales	72.2		65.9		6.3			9.6
Gross Margin	$	176.2	$	155.5	$	20.7		13.3	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	63,044	$	61,261	522	506	290,743	286,903
South Dakota	12,640		9,933		113	108	49,946	49,739
Residential	75,684		71,194		635	614	340,689	336,642
Montana	85,611		85,586		775	780	65,421	64,539
South Dakota	20,706		16,836		231	224	12,642	12,508
Commercial	106,317		102,422		1,006	1,004	78,063	77,047
Industrial	9,772		11,177		538	574	73	75
Other	8,841		8,899		50	52	6,222	6,230
Total Retail Electric	$	200,614	$	193,692	2,229	2,244	425,047	419,994



	Cooling Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	72	107	43	33% colder	67% warmer
South Dakota	98	69	62	42% warmer	58% warmer



	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	1,011	1,097	1,282	8% warmer	21% warmer
South Dakota	1,246	1,180	1,474	6% colder	15% warmer

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



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Lost revenue adjustment mechanism	$	11.8
South Dakota rate increase	10.0
QF adjustment	6.1
MPSC disallowance (adjustment)	0.8
Retail volumes	0.3
Transmission	(0.7		)
Other	(0.9		)
Change in Gross Margin Impacting Net Income	27.4

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(5.9		)
Production tax credits flowed-through trackers	(2.7		)
Property taxes recovered in trackers	1.9
Change in Items Offset Within Net Income	(6.7		)
Increase in Consolidated Gross Margin	$	20.7

Gross margin for items impacting net income increased $27.4 million including the following:


•	The recognition of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings, which was offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs;


•	An increase in South Dakota electric rates;


•	The inclusion in our 2015 results of an increase in our QF liability based on a review of contract assumptions;


•	An adjustment in the disallowance of modeling costs based on the MPSC final order, as discussed above; and


•	An increase in residential and commercial retail volumes, due primarily to customer growth. Warmer spring weather in South Dakota was offset by unfavorable weather in Montana. These increases were partly offset by


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

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


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


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


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

The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. In addition, while

heating and cooling degree days may fluctuate significantly during the second quarter, our electric customer usage is not highly

sensitive to these changes between the heating and cooling seasons. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015



	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	410.8	$	413.7	$	(2.9	)	(0.7	)%
Regulatory amortization	12.7		10.6		2.1			19.8
Total retail revenues	423.5		424.3		(0.8		)	(0.2	)
Transmission	25.3		27.3		(2.0		)	(7.3	)
Ancillary services	0.8		0.8		—			—
Wholesale and other	40.1		5.0		35.1			702.0
Total Revenues	489.7		457.4		32.3			7.1
Total Cost of Sales	155.8		129.8		26.0			20.0
Gross Margin	$	333.9	$	327.6	$	6.3		1.9	%



	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	139,734	$	140,988	1,189	1,172	290,399	286,427
South Dakota	27,878		24,655		281	292	49,928	49,756
Residential	167,612		165,643		1,470	1,464	340,327	336,183
Montana	168,634		175,425		1,568	1,573	65,349	64,454
South Dakota	41,200		35,874		482	481	12,554	12,415
Commercial	209,834		211,299		2,050	2,054	77,903	76,869
Industrial	19,690		22,992		1,073	1,140	73	75
Other	13,616		13,794		73	76	5,445	5,402
Total Retail Electric	$	410,752	$	413,728	4,666	4,734	423,748	418,529



	Cooling Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	72	107	43	33% colder	67% warmer
South Dakota	98	69	62	42% warmer	58% warmer



	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	3,998	3,988	4,570	-	13% warmer
South Dakota	4,920	5,269	5,548	7% warmer	11% warmer

The following summarizes the components of the changes in electric gross margin for the six months ended June 30, 2016 and 2015:



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota rate increase	$	18.6
Lost revenue adjustment mechanism	10.0
QF adjustment	6.1
MPSC disallowance	(9.5		)
Transmission	(2.0		)
Retail volumes	(0.7		)
Other	(1.8		)
Change in Gross Margin Impacting Net Income	20.7

Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(11.8		)
Production tax credits flowed-through trackers	(5.9		)
Property taxes recovered in trackers	3.3
Change in Items Offset Within Net Income	(14.4		)
Increase in Consolidated Gross Margin	$	6.3

This increase in gross margin was due to the same reasons discussed in the three months ended section above, partially offset by the $9.5 million net impact of the MPSC disallowance of previously incurred costs. Retail volumes decreased primarily due to warmer winter weather and lower industrial volumes of a large Montana customer, partly offset by customer growth. In addition, the change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

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, 2016 Compared with the Three Months Ended June 30, 2015



	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	33.1	$	36.9	$	(3.8	)	(10.3	)%
Regulatory amortization	2.4		2.4		—			—
Total retail revenues	35.5		39.3		(3.8		)	(9.7	)
Wholesale and other	9.2		9.9		(0.7		)	(7.1	)
Total Revenues	44.7		49.2		(4.5		)	(9.1	)
Total Cost of Sales	9.5		13.6		(4.1		)	(30.1	)
Gross Margin	$	35.2	$	35.6	$	(0.4	)	(1.1	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	14,228	$	15,666	1,765	1,826	168,006	165,954
South Dakota	3,980		4,423		487	472	39,088	38,697
Nebraska	3,425		3,643		420	384	37,034	36,800
Residential	21,633		23,732		2,672	2,682	244,128	241,451
Montana	7,097		8,026		922	976	23,238	22,989
South Dakota	2,343		2,886		516	493	6,421	6,262
Nebraska	1,673		1,880		336	310	4,707	4,627
Commercial	11,113		12,792		1,774	1,779	34,366	33,878
Industrial	153		159		22	21	259	263
Other	190		169		30	24	158	152
Total Retail Gas	$	33,089	$	36,852	4,498	4,506	278,911	275,744



	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	1,011	1,097	1,282	8% warmer	21% warmer
South Dakota	1,246	1,180	1,474	6% colder	15% warmer
Nebraska	1,038	981	1,206	6% colder	14% warmer

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



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	(1.3	)
Natural gas production	0.9
Lost revenue adjustment mechanism	0.8
Other	(0.5		)
Change in Gross Margin Impacting Net Income	(0.1		)

Gross Margin Item Offset in Operating Expenses
Gas production gathering fees	(0.6		)
Property taxes recovered in trackers	0.3
Change in Item Offset Within Net Income	(0.3		)
Decrease in Consolidated Gross Margin	$	(0.4	)

Gross margin for items impacting net income decreased $0.1 million including the following:


•	A decrease in natural gas volumes due primarily to warmer spring weather, partly offset by customer growth; offset by


•	An increase in natural gas production due to a change in interim rates based on actual costs; and


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

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


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


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

Average natural gas supply prices decreased in 2016 resulting in lower retail revenues and cost of sales as compared with 2015, with no impact to gross margin. In addition, our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015



	Results
	2016			2015			Change			% Change
	(dollars in millions)
Retail revenues	$	117.0		$	138.6		$	(21.6	)	(15.6	)%
Regulatory amortization	(0.6		)	(0.6		)	—			—
Total retail revenues	116.4			138.0			(21.6		)	(15.7	)
Wholesale and other	19.5			21.2			(1.7		)	(8.0	)
Total Revenues	135.9			159.2			(23.3		)	(14.6	)
Total Cost of Sales	41.3			62.1			(20.8		)	(33.5	)
Gross Margin	$	94.6		$	97.1		$	(2.5	)	(2.6	)%



	Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	50,553	$	55,497	6,722	6,588	167,895	165,785
South Dakota	14,128		18,174		1,874	2,038	39,219	38,893
Nebraska	11,244		15,079		1,558	1,703	37,172	37,011
Residential	75,925		88,750		10,154	10,329	244,286	241,689
Montana	24,982		27,921		3,446	3,424	23,231	22,981
South Dakota	8,952		12,132		1,771	1,868	6,442	6,289
Nebraska	5,946		8,538		1,136	1,240	4,727	4,660
Commercial	39,880		48,591		6,353	6,532	34,400	33,930
Industrial	590		725		85	92	261	263
Other	576		555		92	80	158	152
Total Retail Gas	$	116,971	$	138,621	16,684	17,033	279,105	276,034



	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	3,998	3,988	4,570	-	13% warmer
South Dakota	4,920	5,269	5,548	7% warmer	11% warmer
Nebraska	3,989	4,355	4,587	8% warmer	13% warmer

The following summarizes the components of the changes in natural gas gross margin for the six months ended June 30, 2016 and 2015:



	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	(1.1	)
Natural gas production	(0.7		)
Lost revenue adjustment mechanism	0.6
Other	(0.9		)
Change in Gross Margin Impacting Net Income	(2.1		)

Gross Margin Item Offset in Operating Expenses
Gas production gathering fees	(1.0		)
Property taxes recovered in trackers	0.6
Change in Item Offset Within Net Income	(0.4		)
Decrease in Consolidated Gross Margin	$	(2.5	)

This decrease in gross margin was primarily due to the same reasons discussed in the three months ended section above. In addition, average natural gas supply prices decreased in 2016 resulting in lower retail revenues and cost of sales as compared with 2015, with no impact to gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.



LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Funds

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

We issue debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities we utilize available cash flow, debt capacity and equity issuances that allow us to maintain investment grade ratings. We expect to issue incremental debt securities during the second half of 2016 to fund capital investment and maintain liquidity, consistent with our plan to maintain a 50 - 55 percent debt to total capital ratio excluding capital leases. In addition, we expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

Short-term liquidity is provided by internal cash flows, the sale of commercial paper and use of our revolving credit facility. We utilize our short-term borrowings and/or revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. Short-term borrowings may also be used to temporarily fund utility capital requirements. As of June 30, 2016, our total net liquidity was approximately $102.2 million, including $9.0 million of cash and $93.2 million of revolving credit facility availability. Revolving credit facility availability was $97.2 million as of July 15, 2016. During the second quarter of 2016, we issued $60 million of South Dakota First Mortgage Bonds. Proceeds were used to redeem $55 million of First Mortgage Bonds due in 2018.

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



Amount outstanding at period end	$	256.8
Daily average amount outstanding	$	175.3
Maximum amount outstanding	$	256.8

Factors Impacting our Liquidity

Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.

The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult.

As of June 30, 2016, we are under collected on our supply trackers by approximately $9.6 million, as compared with an under collection of $29.4 million as of December 31, 2015, and $9.2 million as of June 30, 2015.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, and impact our trade credit availability. Fitch Ratings (Fitch), Moody’s Investors Service (Moody's) and Standard and Poor’s Ratings Service (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 15, 2016, our current ratings with these agencies are as follows:



	Senior Secured Rating	Senior Unsecured Rating	Commercial Paper	Outlook
Fitch	A	A-	F2	Stable
Moody’s	A1	A3	Prime-2	Negative
S&P	A-	BBB	A-2	Stable

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Cash Flows

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



	Six Months Ended June 30,
	2016			2015
Operating Activities
Net income	$	73.6		$	82.4
Non-cash adjustments to net income	90.1			90.3
Changes in working capital	(26.8		)	7.5
Other noncurrent assets and liabilities	4.1			10.2
Cash Provided by Operating Activities	141.0			190.4

Investing Activities
Property, plant and equipment additions	(121.2		)	(131.2		)
Change in restricted cash	—			9.2
Acquisitions	—			(0.5		)
Other	0.1			0.1
Cash Used in Investing Activities	(121.1		)	(122.4		)

Financing Activities
Issuances of long-term debt, net	5.0			50.0
Issuances (repayments) of short-term borrowings, net	26.9			(47.9		)
Dividends on common stock	(47.9		)	(44.8		)
Financing costs	(5.3		)	(11.7		)
Other	(1.6		)	(1.1		)
Cash Used in Financing Activities	(22.9		)	(55.5		)

(Decrease) increase in Cash and Cash Equivalents	$	(3.0	)	$	12.5
Cash and Cash Equivalents, beginning of period	$	12.0		$	20.4
Cash and Cash Equivalents, end of period	$	9.0		$	32.9

Cash Provided by Operating Activities

As of June 30, 2016, cash and cash equivalents were $9.0 million as compared with $12.0 million at December 31, 2015 and $32.9 million at June 30, 2015. Cash provided by operating activities totaled $141.0 million for the six months ended June 30, 2016 as compared with $190.4 million during the six months ended June 30, 2015. This decrease in operating cash flows is primarily due to refunds associated with the DGGS FERC ruling of approximately $30.8 million ($27.3 million of deferred revenues plus accrued interest of $3.5 million) to customers during the first six months of 2016, and lower net income.

Cash Used in Investing Activities

Cash used in investing activities decreased by approximately $1.3 million as compared with the first six months of 2015. Plant additions during 2016 include maintenance additions of approximately $63.4 million, capacity related capital expenditures of approximately $34.4 million, and infrastructure capital expenditures of approximately $23.4 million. Plant additions during the first six months of 2015 included maintenance additions of approximately $85.8 million, supply related capital expenditures of approximately $19.8 million, which were primarily related to electric generation facilities in South Dakota, and infrastructure capital expenditures of approximately $25.6 million.

Cash Used in Financing Activities

Cash used in financing activities totaled $22.9 million during the six months ended June 30, 2016 as compared with $55.5 million during the six months ended June 30, 2015. During the six months ended June 30, 2016, net cash used in financing activities includes the payment of dividends of $47.9 million and the payment of financing costs of $5.3 million, partially offset

by net issuances of commercial paper of $26.9 million and net proceeds from the issuance of debt of $5.0 million. During the six months ended June 30, 2015, net cash used in financing activities consisted of net repayments of commercial paper of $47.9 million, the payment of dividends of $44.8 million, and the payment of financing costs of $11.7 million, offset in part by net proceeds from the issuance of debt of $50.0 million.

Debt Issuance - In June 2016, we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026. These bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018.

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



	Total		2016		2017		2018		2019		2020		Thereafter
	(in thousands)
Long-term debt	$	1,773,714	$	—	$	—	$	—	$	250,000	$	—	$	1,523,714
Capital leases	27,278		953		1,979		2,133		2,298		2,476		17,439
Short-term borrowings	256,806		256,806		—		—		—		—		—
Estimated pension and other postretirement obligations (1)	66,180		12,011		13,661		13,554		13,489		13,465		N/A
Qualifying facilities liability (2)	918,813		36,785		74,607		76,703		78,836		80,984		570,898
Supply and capacity contracts (3)	1,793,018		121,510		197,966		151,017		147,236		112,364		1,062,925
Contractual interest payments on debt (4)	1,422,676		42,224		83,825		83,635		73,620		65,695		1,073,677
Environmental remediation obligations (1)	6,740		1,140		1,650		1,650		1,500		800		N/A
Total Commitments (5)	$	6,265,225	$	471,429	$	373,688	$	328,692	$	566,979	$	275,784	$	4,248,653

_________________________


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


(3)	We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years.


(4)	For our variable rate short-term borrowings outstanding, we have assumed an average interest rate of 0.89% through maturity.


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



CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

As of June 30, 2016, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2015. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%. To more cost effectively meet short-term cash requirements, we issue commercial paper supported by our revolving credit facility. Since commercial paper terms are short-term, we are subject to interest rate risk. As of June 30, 2016, we had approximately $256.8 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately $2.6 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is substantially mitigated because these commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by applicable state regulatory commissions.

Counterparty Credit Risk

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


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and communicated to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

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

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

See Note 13, Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.

ITEM 1A. RISK FACTORS

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.

We are subject to potential unfavorable state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs, which could adversely impact our results of operations and liquidity.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates established by several regulatory commissions. These rates are generally set based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs.

In addition to general rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. Our wholesale costs for electricity and natural gas supply are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contractual obligations. As these variables change, we adjust our rates through our monthly trackers, which are subject to approval by the applicable regulatory commissions. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we do not recover some of our costs, which could adversely impact our results of operations.

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

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

•In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 by the MPSC as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in the kWh sales lost due to energy efficiency programs through our supply tracker. Lost revenues were removed prospectively effective December 1, 2015.

•In October 2013, the MPSC concluded that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

We appealed the October 2013 decision regarding DGGS outage costs to the Montana District Court, which, in August 2015, upheld the MPSC’s decision. In October 2015, we appealed the District Court’s decision to the Montana Supreme Court. We expect the matter to be fully briefed by the end of July 2016. Also, in June 2016, we filed an appeal of the MPSC decision in our 2014/2015 electric tracker filing regarding the disallowance of portfolio modeling costs in Montana District Court.

In addition to our supply trackers, we file an annual property tax tracker with the MPSC for an automatic rate adjustment of our Montana property taxes, which allows recovery of 60 percent of the change in property taxes. Adjusted rates are typically effective January 1st of each year. The MPSC has identified concerns with the amount of annual increases proposed by the Montana Department of Revenue. Any change in recovery of property taxes could have a material impact on our results of operations.

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

In addition, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. In March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our costs.

In May 2016, we received an order from the FERC denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had deferred cumulative revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order. In June 2016, we filed a petition for review with the U.S. Circuit Court of Appeals for the District of Columbia Circuit. The briefing schedule for this appeal has not been established. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We are evaluating options to use DGGS in combination with other generation resources, including our hydro facilities, to minimize portfolio costs, which may facilitate cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. If we are not able to obtain cost recovery of DGGS we may be required to record an impairment charge, which could have a material adverse effect on our operating results.

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

Our ability to invest in additional generation is impacted by regulatory and public policy. Under the Public Utility Regulatory Policies Act of 1978, electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (QFs). Our requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. In addition, the cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs.

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

We must also comply with established reliability standards and requirements, which apply to North American Electric Reliability Corporation (NERC) functions in both the Midwest Reliability Organization for our South Dakota operations and Western Electric Coordination Council for our Montana operations. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, audits, periodic data

submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as $1 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.

We are also subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.

We are subject to existing, and potential future, federal and state legislation. In the planning and management of our operations, we must address the effects of legislation within a regulatory framework. Federal and state laws can significantly impact our operations, whether it is new or revised statutes directly affecting the electric and gas industry, or other issues such as taxes. In addition, new or revised statutes can also materially affect our operations through impacting existing regulations or requiring new regulations. These changes are ongoing, and we cannot predict the future course of changes or the ultimate effect that this changing environment will have on us. Changes in laws, and the resulting regulations and tariffs and how they are implemented and interpreted, may have a material adverse effect on our businesses, financial condition, results of operations and cash flows.

In March 2016, the U.S. Senate passed the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act (SAFE PIPES Act), which would reauthorize appropriations for the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) safety programs through 2019. The bill prioritizes PHMSA's completion of outstanding regulations. In addition, in March 2016, PHMSA proposed revisions to safety standards for natural gas transmission and gathering pipelines. The long-anticipated proposal could impose significant regulatory requirements for additional miles of natural gas pipeline, including pipelines constructed prior to 1970 which were previously exempt from PHMSA regulations related to pressure testing. It would also create a new "Moderate Consequence Area" category to expand safety protocols to pipelines in moderately populated areas. Costs incurred to comply with the proposed regulations may be material.

We are subject to extensive and changing environmental laws and regulations and potential environmental liabilities, which could have a material adverse effect on our liquidity and results of operations.

We are subject to extensive laws and regulations imposed by federal, state, and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations. We believe that we are in compliance with environmental regulatory requirements; however, possible future developments, such as more stringent environmental laws and regulations, and the timing of future enforcement proceedings that may be taken by environmental authorities, could affect our costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

National and international actions have been initiated to address global climate change and the contribution of GHG emissions including, most significantly, carbon dioxide. In August 2015, the EPA released final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed natural gas combined cycle units. In a separate action that also affects power plants, in August 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d) (the Clean Power Plan or CPP).

The CPP reduction of 47.4 percent in carbon dioxide emissions in Montana by 2030 is the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, the CPP's target reduction is applied on a statewide basis, and investments made prior to 2012 are not counted in the CPP's 2030 target. We asked the BBER to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing the Colstrip generating facilities in southeast Montana as a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Unit 4 represents approximately 25 percent of our customer needs. Closing Colstrip would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing Colstrip would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to lower electric customer bills.

We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the CPP and the various regulations discussed above that have been issued or proposed. Each state is

required by the CPP to submit a satisfactory plan to EPA by September 2018. The state plans will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number of vintages of allowances that will be allocated to our facilities. Until the plans are submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us.

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

Requirements to reduce GHG emissions 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 the impact of these risks on our results of operations.

We are evaluating the implications of these rules and technology available to achieve the CO₂ emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters nor what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

Many of these environmental laws and regulations provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our

customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and has the effect of increasing rates unless retail rates are designed to share the costs of the distribution grid across all customers that benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy.

Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. Our electricity supply resource procurement plan includes an expected load growth assumption of 0.8 percent annually, which reflects low customer and usage increases, offset in part by these efficiency measures. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, transmission availability and the availability of generation, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial position could be adversely affected. Higher temperatures may also decrease the Montana snowpack, which may result in dry conditions and an increased threat of forest fires. Forest fires could threaten our communities and electric transmission lines and facilities. Any damage caused as a result of forest fires could negatively impact our financial condition, results of operations or cash flows. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs. There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events.

Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. Severe weather impacts our service territories, primarily through thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. We derive a significant portion of our power supply from hydroelectric facilities. Because of our heavy reliance on hydroelectric generation, snowpack, the timing of run-off, drought conditions, and the availability of water can significantly affect operations. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.

Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber (such as hacking and viruses) and physical security breaches and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. These assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including cyber attacks and other disruptive activities on third party facilities that are interconnected to us through the regional transmission grid or natural gas pipeline infrastructure. Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.

We rely on information technology networks and systems to operate our critical infrastructure, engage in asset management activities, and process, transmit and store electronic information including customer and employee information. Further, our infrastructure, networks and systems are interconnected to external networks and neighboring critical infrastructure systems. Security breaches could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. In particular, any data loss or information security lapses resulting in the compromise of personal information or the improper use or disclosure of sensitive or classified information could result in claims, remediation costs, regulatory sanctions, loss of current and future contracts, and serious harm to our reputation.

Security threats continue to evolve and adapt. Cyber or physical attacks, terrorist acts, or disruptive activities could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Our plans for future expansion through the acquisition of assets including natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.

Acquisitions include a number of risks, including but not limited to, additional costs, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, securing adequate capital to support the transaction, and regulatory approval. Uncertainties exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

Our business strategy also includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

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

Inherent in our electric and natural gas operations are a variety of hazards and operating risks, such as fires, electric contacts, leaks, explosions and mechanical problems. These risks could cause a loss of human life, significant damage to property, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our natural gas transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks potentially is greater.

Our owned and jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs.

The six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facilities agreement among the owners of all four units. As discussed above, the proposed consent decree relating to the Colstrip litigation call for Units 1 and 2 to be shut down by 2022. If Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4. In addition, in May 2016, Talen provided a two-year notice of its intent to resign as the operator of Colstrip. We and the other owners are working to select a new operator, which we expect will increase operating costs. However, at this time we do not anticipate these increases will be material to our financial results.

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

We also rely on a limited number of suppliers of coal for our electric generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier.

Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

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

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

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

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.

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit 3.1— Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated May 3, 2016 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).

Exhibit 3.2— Amended and Restated Bylaws of NorthWestern Corporation, dated May 12, 2016 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).

Exhibit 4.1— Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



			NorthWestern Corporation
Date:	July 22, 2016	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer



EXHIBIT INDEX



Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated May 3, 2016 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
3.2		Amended and Restated Bylaws of NorthWestern Corporation, dated May 12, 2016 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
4.1		Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).
*31.1		Certification of chief executive officer.
*31.2		Certification of chief financial officer.
*32.1		Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		XBRL Taxonomy Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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*	Filed herewith