10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(mark one)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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. 69th Street, Sioux Falls, South Dakota	57108
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code: 605-978-2900

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

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

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

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

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

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

Common Stock, Par Value $0.01

48,327,642 shares outstanding at October 14, 2016

1

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2016 and 2015	4
	Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2016 and 2015	5
	Condensed Consolidated Balance Sheets — September 30, 2016 and December 31, 2015	6
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2016 and 2015	7
	Condensed Consolidated Statements of Shareholders' Equity — Nine Months Ended September 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	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	59
PART II. OTHER INFORMATION		60
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 6.	Exhibits	67
SIGNATURES		69

2

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• 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.

3

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues
Electric	$	266,629		$	238,513		$	756,374		$	695,921
Gas	34,369			34,226			170,283			193,389
Total Revenues	300,998			272,739			926,657			889,310
Operating Expenses
Cost of sales	96,156			73,577			293,283			265,495
Operating, general and administrative	68,290			79,296			220,730			222,139
Property and other taxes	40,673			35,712			111,302			100,953
Depreciation and depletion	39,763			35,693			119,551			107,239
Total Operating Expenses	244,882			224,278			744,866			695,826
Operating Income	56,116			48,461			181,791			193,484
Interest Expense, net	(21,049		)	(22,043		)	(71,979		)	(68,101		)
Other (Loss) Income	(121		)	3,769			4,176			5,429
Income Before Income Taxes	34,946			30,187			113,988			130,812
Income Tax Benefit (Expense)	9,659			(6,389		)	4,240			(24,616		)
Net Income	$	44,605		$	23,798		$	118,228		$	106,196
Average Common Shares Outstanding	48,315			47,065			48,289			47,029
Basic Earnings per Average Common Share	$	0.92		$	0.51		$	2.45		$	2.26
Diluted Earnings per Average Common Share	$	0.92		$	0.51		$	2.44		$	2.25
Dividends Declared per Common Share	$	0.50		$	0.48		$	1.50		$	1.44

See Notes to Condensed Consolidated Financial Statements

4

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Net Income	$	44,605		$	23,798		$	118,228		$	106,196
Other comprehensive income (loss), net of tax:
Foreign currency translation	26			233			(84		)	445
Cash flow hedges:
Reclassification of net gains on derivative instruments	(1,506		)	(555		)	(1,432		)	(735		)
Total Other Comprehensive Loss	(1,480		)	(322		)	(1,516		)	(290		)
Comprehensive Income	$	43,125		$	23,476		$	116,712		$	105,906

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30, 2016			December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	5,063		$	11,980
Restricted cash	6,706			6,634
Accounts receivable, net	116,821			154,410
Inventories	54,311			53,458
Regulatory assets	44,501			51,348
Other	10,937			8,830
Total current assets	238,339			286,660
Property, plant, and equipment, net	4,161,993			4,059,499
Goodwill	357,586			357,586
Regulatory assets	592,432			517,223
Other noncurrent assets	43,591			43,727
Total Assets	$	5,393,941		$	5,264,695
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of capital leases	$	1,942		$	1,837
Short-term borrowings	222,311			229,874
Accounts payable	57,217			74,511
Accrued expenses	241,185			183,988
Regulatory liabilities	24,159			80,990
Total current liabilities	546,814			571,200
Long-term capital leases	24,859			26,325
Long-term debt	1,794,519			1,768,183
Deferred income taxes	575,812			501,532
Noncurrent regulatory liabilities	392,857			378,711
Other noncurrent liabilities	410,273			418,570
Total Liabilities	3,745,134			3,664,521
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,936 and 48,327,642 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	520			518
Treasury stock at cost	(95,852		)	(93,948		)
Paid-in capital	1,381,930			1,376,291
Retained earnings	372,321			325,909
Accumulated other comprehensive loss	(10,112		)	(8,596		)
Total Shareholders' Equity	1,648,807			1,600,174
Total Liabilities and Shareholders' Equity	$	5,393,941		$	5,264,695

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2016			2015
OPERATING ACTIVITIES:
Net income	$	118,228		$	106,196
Items not affecting cash:
Depreciation and depletion	119,551			107,239
Amortization of debt issue costs, discount and deferred hedge gain	907			1,301
Stock-based compensation costs	4,474			3,275
Equity portion of allowance for funds used during construction	(3,053		)	(6,568		)
Gain on disposition of assets	(15		)	(28		)
Deferred income taxes	(4,720		)	27,019
Changes in current assets and liabilities:
Restricted cash	(72		)	(735		)
Accounts receivable	37,589			46,025
Inventories	(853		)	(3,598		)
Other current assets	(2,107		)	4,006
Accounts payable	(16,568		)	(21,655		)
Accrued expenses	60,852			19,307
Regulatory assets	6,847			8,985
Regulatory liabilities	(56,831		)	12,739
Other noncurrent assets	(4,234		)	(2,240		)
Other noncurrent liabilities	(2,007		)	3,209
Cash Provided by Operating Activities	257,988			304,477
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(203,998		)	(203,324		)
Acquisitions	—			(143,328		)
Proceeds from sale of assets	1,352			30,209
Change in restricted cash	—			11,758
Cash Used in Investing Activities	(202,646		)	(304,685		)
FINANCING ACTIVITIES:
Treasury stock activity	(727		)	(829		)
Dividends on common stock	(71,816		)	(67,145		)
Issuance of long-term debt	249,660			270,000
Repayments on long-term debt	(225,205		)	(150,024		)
Repayments of short-term borrowings, net	(7,563		)	(49,897		)
Financing costs	(6,608		)	(12,124		)
Cash Used in Financing Activities	(62,259		)	(10,019		)
Decrease in Cash and Cash Equivalents	(6,917		)	(10,227		)
Cash and Cash Equivalents, beginning of period	11,980			20,362
Cash and Cash Equivalents, end of period	$	5,063		$	10,135
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(2,922	)	$	27
Interest	56,118			52,106
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	11,803			8,932

See Notes to Condensed Consolidated Financial Statements

7

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	—	—	—		—			—			106,196			—			106,196
Foreign currency translation adjustment	—	—	—		—			—			—			445			445
Reclassification of net gains on derivative instruments from Other Comprehensive Income (OCI) to net income, net of tax	—	—	—		—			—			—			(735		)	(735		)
Stock-based compensation	166	—	—		3,304			(1,926		)	—			—			1,378
Issuance of shares	—	13	2		469			453			—			—			924
Dividends on common stock ($1.44 per share)	—	—	—		—			—			(67,145		)	—			(67,145		)
Balance at September 30, 2015	50,688	3,620	$	507	$	1,317,617		$	(94,031	)	$	303,809		$	(9,056	)	$	1,518,846
Balance at December 31, 2015	51,789	3,617	$	518	$	1,376,291		$	(93,948	)	$	325,909		$	(8,596	)	$	1,600,174
Net income	—	—	—		—			—			118,228			—			118,228
Foreign currency translation adjustment	—	—	—		—			—			—			(84		)	(84		)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—			—			—			(1,432		)	(1,432		)
Stock-based compensation	168	13	—		5,650			(1,904		)	—			—			3,746
Issuance of shares	—	—	2		(11		)				—			—			(9		)
Dividends on common stock ($1.50 per share)	—	—	—		—			—			(71,816		)	—			(71,816		)
Balance at September 30, 2016	51,957	3,630	$	520	$	1,381,930		$	(95,852	)	$	372,321		$	(10,112	)	$	1,648,807

8

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 September 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 $252.9 million through 2024.

(2) New Accounting Standards

Accounting Standards Issued

In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The 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.

9

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.

In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows.

Accounting Standards Adopted

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 Natural Gas Delivery and Production Rate Filing

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

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

Montana Electric and Natural Gas Tracker Filings

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

10

During the second quarter of 2016, we filed our 2016 annual electric and natural gas tracker filings for the 2015/2016 tracker period. The MPSC issued orders 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. In May 2016, we received the final written order in the Consolidated Docket. The written order upheld the March 2016 decision regarding replacement power costs and clarified the disallowance of modeling costs, resulting in a reduction of the disallowance of $0.8 million, which was reflected as a reduction in cost of sales in the second quarter of 2016. Based on the final orders, the impact of the disallowance totals $12.4 million, which includes interest of $2.9 million and is recorded in the Condensed Consolidated Statement of Income for the nine months ended September 30, 2016.

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

Electric and Natural Gas Lost Revenue Adjustment Mechanism- 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 in the second quarter of 2016.

Hydro Compliance Filing

In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016. The adjustment to rates is being refunded to customers over 12 months, and as of September 30, 2016, we have deferred revenue remaining of approximately $2.6 million that we expect to refund to customers by the end of 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

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revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of September 30, 2016, the DGGS net property, plant and equipment is approximately $160 million. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are 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.

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(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 September 30,
	2016					2015
Income Before Income Taxes	$	34,946				$	30,187
Income tax calculated at 35% federal statutory rate	12,231			35.0	%	10,565			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(615		)	(1.8	)	(857		)	(2.8	)
Flow-through repairs deductions	(18,995		)	(54.4	)	(2,779		)	(9.2	)
Production tax credits	(2,218		)	(6.3	)	(733		)	(2.4	)
Plant and depreciation of flow through items	(243		)	(0.7	)	(374		)	(1.2	)
Prior year permanent return to accrual adjustments	—			—		1,025			3.4
Other, net	181			0.6		(458		)	(1.6	)
	(21,890		)	(62.6	)	(4,176		)	(13.8	)
	$	(9,659	)	(27.6	)%	$	6,389		21.2	%

	Nine Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	113,988				$	130,812
Income tax calculated at 35% federal statutory rate	39,896			35.0	%	45,784			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(2,740		)	(2.4	)	(329		)	(0.3	)
Flow-through repairs deductions	(32,640		)	(28.6	)	(17,240		)	(13.2	)
Production tax credits	(7,317		)	(6.4	)	(2,645		)	(2.0	)
Plant and depreciation of flow through items	(1,427		)	(1.3	)	(1,000		)	(0.8	)
Prior year permanent return to accrual adjustments	(128		)	(0.1	)	1,025			0.8
Other, net	116			0.1		(979		)	(0.7	)
	(44,136		)	(38.7	)	(21,168		)	(16.2	)
	$	(4,240	)	(3.7	)%	$	24,616		18.8	%

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

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

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $90.0 million as of September 30, 2016, including approximately $66.6 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2016 we recognized $0.5 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of September 30, 2016, we had $0.5 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2015, we did not recognize any expense for interest or penalties, and did not have any amounts accrued 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 nine months ended September 30, 2016. Goodwill by segment is as follows for both September 30, 2016 and December 31, 2015 (in thousands):

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

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(6) Comprehensive Loss

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

	Three Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	26		$	—	$	26		$	233		$	—	$	233
Reclassification of net gains on derivative instruments	(2,448		)	942		(1,506		)	(901		)	346		(555		)
Other comprehensive loss	$	(2,422	)	$	942	$	(1,480	)	$	(668	)	$	346	$	(322	)

	Nine Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(84	)	$	—	$	(84	)	$	445		$	—	$	445
Reclassification of net gains on derivative instruments	(2,324		)	892		(1,432		)	(1,187		)	452		(735		)
Other comprehensive loss	$	(2,408	)	$	892	$	(1,516	)	$	(742	)	$	452	$	(290	)

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

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

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

		Three Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,940	)	$	(937	)	$	1,245	(8,632		)
Other comprehensive income before reclassifications		—			—			26		26
Amounts reclassified from AOCL	Interest Expense	(1,506		)	—			—		(1,506		)
Net current-period other comprehensive (loss) income		(1,506		)	—			26		(1,480		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271	$	(10,112	)

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

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		Nine Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	$	(937	)	$	1,355		(8,596		)
Other comprehensive loss before reclassifications		—			—			(84		)	(84		)
Amounts reclassified from AOCL	Interest Expense	(1,432		)	—			—			(1,432		)
Net current-period other comprehensive loss		(1,432		)	—			(84		)	(1,516		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271		$	(10,112	)

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

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(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 September 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

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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):

	Location of amount reclassified from AOCL to Income	Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016
Interest rate contracts	Interest Expense	$	2,324

A pre-tax loss of approximately $17.2 million is remaining in AOCL as of September 30, 2016, and we expect to reclassify approximately $0.6 million of pre-tax losses 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.

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	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Margin Cash Collateral Offset		Total Net Fair Value
	(in thousands)
September 30, 2016
Restricted cash	$	6,350	$	—	$	—	$	—	$	6,350
Rabbi trust investments	25,057		—		—		—		25,057
Total	$	31,407	$	—	$	—	$	—	$	31,407
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):

	September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,794,519	$	1,950,837	$	1,768,183	$	1,844,974

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

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

(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. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018. In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended.

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

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issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

(10) Segment Information

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

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

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

Three Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	266,629			$	34,369		$	—		$	—	$	300,998
Cost of sales	89,681			6,475			—			—		96,156
Gross margin	176,948			27,894			—			—		204,842
Operating, general and administrative	50,460			19,141			(1,311		)	—		68,290
Property and other taxes	32,343			8,328			2			—		40,673
Depreciation and depletion	32,549			7,206			8			—		39,763
Operating income (loss)	61,596			(6,781		)	1,301			—		56,116
Interest expense	(19,099		)	(1,249		)	(701		)	—		(21,049		)
Other income (loss)	982			345			(1,448		)	—		(121		)
Income tax benefit	7,946			1,169			544			—		9,659
Net income (loss)	$	51,425		$	(6,516	)	$	(304	)	$	—	$	44,605
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	66,322		$	16,430		$	—		—		$	82,752

Three Months Ended
September 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	238,513		$	34,226		$	—		$	—	$	272,739
Cost of sales	66,197			7,380			—			—		73,577
Gross margin	172,316			26,846			—			—		199,162
Operating, general and administrative	58,298			19,843			1,155			—		79,296
Property and other taxes	28,648			7,062			2			—		35,712
Depreciation and depletion	28,476			7,209			8			—		35,693
Operating income (loss)	56,894			(7,268		)	(1,165		)	—		48,461
Interest expense	(19,078		)	(2,562		)	(403		)	—		(22,043		)
Other income	1,832			507			1,430			—		3,769
Income tax (expense) benefit	(6,553		)	1,883			(1,719		)	—		(6,389		)
Net income (loss)	$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798
Total assets	$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078
Capital expenditures	$	57,813		$	14,341		$	—		$	—	$	72,154

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Nine Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	756,374		$	170,283		$	—		$	—	$	926,657
Cost of sales	245,470			47,813			—			—		293,283
Gross margin	510,904			122,470			—			—		633,374
Operating, general and administrative	157,471			61,638			1,621			—		220,730
Property and other taxes	87,094			24,200			8			—		111,302
Depreciation and depletion	97,614			21,913			24			—		119,551
Operating income (loss)	168,725			14,719			(1,653		)	—		181,791
Interest expense	(65,273		)	(5,018		)	(1,688		)	—		(71,979		)
Other income	2,136			925			1,115			—		4,176
Income tax benefit (expense)	3,600			(574		)	1,214			—		4,240
Net income (loss)	$	109,188		$	10,052		$	(1,012	)	$	—	$	118,228
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	165,885		$	38,113		$	—		—		$	203,998

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

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(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
	September 30, 2016	September 30, 2015
Basic computation	48,314,783	47,065,082
Dilutive effect of:
Performance share awards (1)	154,537	245,463
Diluted computation	48,469,320	47,310,545

	Nine Months Ended
	September 30, 2016	September 30, 2015
Basic computation	48,288,678	47,028,924
Dilutive effect of:
Performance share awards (1)	154,889	245,460
Diluted computation	48,443,567	47,274,384

______________

(1)          Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

(12) Employee Benefit Plans

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

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

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	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	8,819			$	9,272		$	369		$	395
Interest cost	19,658			19,631			596			590
Expected return on plan assets	(21,186		)	(23,671		)	(782		)	(727		)
Amortization of prior service cost	185			185			(1,412		)	(1,412		)
Recognized actuarial loss	7,416			7,976			236			289
Net Periodic Benefit Cost (Income)	$	14,892		$	13,393		$	(993	)	$	(865	)

(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 September 30, 2016, we have a reserve of approximately $30.3 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

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

Manufactured Gas Plants - Approximately $23.7 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of September 30, 2016, the reserve for remediation costs at this site is approximately $11.1 million, and we estimate that approximately $6.5 million of this amount will be incurred during the next five years.

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

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

An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. The additional investigation work began in December 2015 and has continued in 2016. The result of the additional investigation work may lead to the development of site-specific risk-based remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide (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 were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The initial performance period for compliance under the CPP would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program 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

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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 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, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility in southeast Montana as a scenario for complying with the federal 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, and on September 27, 2016, the Court held oral argument in the matter. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018.

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

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

Requirements to reduce GHG emissions 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

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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

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Association, Montana Environmental Information Center (MEIC), and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. 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, did not 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. In 2016, Coyote completed installation of control equipment to maintain compliance with the lower NOx emissions of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown. The cost of the control equipment was 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 of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4.

On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief 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

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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. After filing the Second Amended Complaint, Plaintiffs indicated that they were no longer pursuing a number of claims and projects thereby reducing their total to eight claims 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.

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

The consent decree gave the Plaintiffs and Defendants each the right to seek recovery of attorneys’ fees and costs from the other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. While we cannot predict an outcome on the opposing motions seeking attorneys’ fees and costs, we do not anticipate that the outcome will have a significant impact on our results of operations or cash flows.

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, ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $65.6 million. We dispute 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

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

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

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

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

On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court), and Talen consented to our removal. On April 27, 2016, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with the Great Falls Reach in light of the United States Supreme Court’s decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment.

On May 19, 2016, the State asked the Federal District Court to remand the case back to the State District Court. The parties have fully briefed the issue and we have requested oral argument. Talen’s and our motions to dismiss, the State’s motions for remand and our request for oral argument, remain pending before the Federal District Court.

We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If, on remand, the Federal District Court (or the State District Court if the case is remanded back to it) determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $7.0 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Other Legal Proceedings

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

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

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 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 THIRD QUARTER 2015 RESULTS

	Quarter-over-Quarter Change
Gross Margin by Segment(1)
Electric	$4.6M	é	2.7%
Natural Gas	$1.1M	é	4.1%
Operating Income	$7.6M	é	15.8%
Net Income	$20.8M	é	87.4%
EPS (Diluted)	$0.41	é	80.4%

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

SIGNIFICANT DEVELOPMENTS IN Q3 2016

Ÿ	An increase in net income of $20.8 million, primarily due to a $15.3 million tax benefit as part of a tax accounting change related to costs to repair generation property along with improved gross margin driven by an increase in South Dakota electric rates.
Ÿ	Filed a Montana natural gas delivery service and production case requesting an annual increase in base rates of approximately $10.9 million.
Ÿ	Received proceeds from the City of Forsyth's issuance of $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds at a fixed interest rate of 2.00% maturing in 2023. Proceeds plus available funds were used to redeem the City of Forsyth's 4.65%, $170.2 million Pollution Control Revenue Bonds due 2023.
Ÿ	Issuance of $45 million of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes.

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

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SIGNIFICANT TRENDS AND REGULATION

Montana Natural Gas Delivery and Production Rate Filing

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

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

Generation Tax Repairs

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

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

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.

In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. In May 2016, we received the final written order in the Consolidated Docket. The written order clarified the disallowance of modeling costs, resulting in a reduction of the disallowance recorded during the second quarter of 2016.

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

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

Electric and Natural Gas Lost Revenue Adjustment Mechanism - 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.

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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 second quarter of 2016 based on the final orders in our tracker filings.

Hydro Compliance Filing

The MPSC order approving our acquisition of the hydro assets provided that customers would have no financial risk related to our temporary ownership of the Kerr facility, with a compliance filing required upon completion of the transfer to the Confederated Salish and Kootenai Tribes (CSKT). We sold any excess system generation, which was primarily due to 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 hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016.

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

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

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are able to shift the utilization of DGGS to additional alternative uses, optimizing our generation portfolio. In support of our 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/

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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.

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RESULTS OF OPERATIONS

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

Non-GAAP Financial Measure

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

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OVERALL CONSOLIDATED RESULTS

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

	Three Months Ended September 30,
	2016		2015		Change		% Change
	(dollars in millions)
Operating Revenues
Electric	$	266.6	$	238.5	$	28.1	11.8	%
Natural Gas	34.4		34.2		0.2		0.6
Total Operating Revenues	$	301.0	$	272.7	$	28.3	10.4	%

	Three Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	89.7	$	66.2	$	23.5		35.5	%
Natural Gas	6.5		7.4		(0.9		)	(12.2	)
Total Cost of Sales	$	96.2	$	73.6	$	22.6		30.7	%

	Three Months Ended September 30,
	2016		2015		Change		% Change
	(dollars in millions)
Gross Margin
Electric	$	176.9	$	172.3	$	4.6	2.7	%
Natural Gas	27.9		26.8		1.1		4.1
Total Gross Margin	$	204.8	$	199.1	$	5.7	2.9	%

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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	$	9.2
Natural gas retail volumes	1.4
Lost revenue adjustment mechanism	(1.8		)
Electric retail volumes	(0.4		)
Electric transmission	(0.4		)
Natural gas production	(0.2		)
Other	(0.3		)
Change in Gross Margin Impacting Net Income	7.5
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(4.3		)
Production tax credits flowed-through trackers	(2.1		)
Natural gas production gathering fees	(0.1		)
Property taxes recovered in trackers	4.7
Change in Items Offset Within Net Income	(1.8		)
Increase in Consolidated Gross Margin	$	5.7

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

• An increase in South Dakota electric rates; and

• An increase in natural gas retail volumes due primarily to colder late summer weather in our Montana jurisdiction and customer growth.

These increases were partly offset by:

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

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

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

• A decrease in natural gas production margin due to lower overhead fees.

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

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

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

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

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

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	Three Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	68.3	$	79.3	$	(11.0	)	(13.9	)%
Property and other taxes	40.7		35.7		5.0			14.0
Depreciation and depletion	39.8		35.7		4.1			11.5
	$	148.8	$	150.7	$	(1.9	)	(1.3	)%

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

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

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

• 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);

• 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);

• Lower DSIP related expenses;

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

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

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

Property and other taxes were $40.7 million for the three months ended September 30, 2016, as compared with $35.7 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 based on valuation reports received from the Montana Department of Revenue. In the third quarter of 2016, we increased our annual property tax expense estimate by approximately $5.4 million based on an updated valuation report. We update to actual expense when we receive our Montana property tax bills in November, and do not expect the November 2016 bills to be significantly different from our current estimate. Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and recover these amounts. The MPSC has authorized recovery of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) as compared to the related amount included in rates during our last general rate case.

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Depreciation and depletion expense was $39.8 million for the three months ended September 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 September 30, 2016 was $56.1 million as compared with $48.5 million in the same period of 2015. This increase was primarily due to the increase in gross margin driven by the South Dakota rate increase as discussed above.

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

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

Consolidated income tax benefit for the three months ended September 30, 2016 was $9.7 million, as compared with income tax expense of $6.4 millionin the same period of 2015. Our effective tax rate for the three months ended September 30, 2016 was (27.6)% as compared with 21.2% for the same period of 2015. We currently expect our 2016 effective tax rate to range between (3)% - 1%.

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

	Three Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	34.9				$	30.2
Income tax calculated at 35% federal statutory rate	12.2			35.0	%	10.6			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(0.6		)	(1.8	)	(0.9		)	(2.8	)
Flow-through repairs deductions	(19.0		)	(54.4	)	(2.8		)	(9.2	)
Production tax credits	(2.2		)	(6.3	)	(0.7		)	(2.4	)
Plant and depreciation of flow through items	(0.2		)	(0.7	)	(0.4		)	(1.2	)
Prior year permanent return to accrual adjustments	—			—		1.0			3.4
Other, net	0.1			0.6		(0.4		)	(1.6	)
	(21.9		)	(62.6	)	(4.2		)	(13.8	)
	$	(9.7	)	(27.6	)%	$	6.4		21.2	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. During the third quarter of 2016, we filed a tax accounting method change with the IRS related to costs to repair generation property, as discussed above in the overview. This resulted in an income tax benefit of approximately $15.5 million during the three months ended September 30, 2016, of which approximately $12.5 million is related to 2015 and prior tax years, and is reflected in the flow-through repairs deductions line above.

Consolidated net income for the three months ended September 30, 2016 was $44.6 million as compared with $23.8 million for the same period in 2015. This increase was primarily due to lower income taxes due to the adoption of a tax accounting method change and improved gross margin due to the South Dakota electric rate increase.

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

	Nine Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Operating Revenues
Electric	$	756.4	$	695.9	$	60.5		8.7	%
Natural Gas	170.3		193.4		(23.1		)	(11.9	)
Total Operating Revenues	$	926.7	$	889.3	$	37.4		4.2	%

	Nine Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Cost of Sales
Electric	$	245.5	$	196.0	$	49.5		25.3	%
Natural Gas	47.8		69.5		(21.7		)	(31.2	)
Total Cost of Sales	$	293.3	$	265.5	$	27.8		10.5	%

	Nine Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Gross Margin
Electric	$	510.9	$	499.9	$	11.0		2.2	%
Natural Gas	122.5		123.9		(1.4		)	(1.1	)
Total Gross Margin	$	633.4	$	623.8	$	9.6		1.5	%

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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	$	27.8
Lost revenue adjustment mechanism	8.8
Electric QF adjustment	6.1
Natural gas retail volumes	0.3
MPSC disallowance	(9.5		)
Electric transmission	(2.3		)
Natural gas production	(1.4		)
Electric retail volumes	(1.1		)
Other	(2.6		)
Change in Gross Margin Impacting Net Income	26.1
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(16.0		)
Production tax credits flowed-through trackers	(8.0		)
Natural gas production gathering fees	(1.1		)
Property taxes recovered in trackers	8.6
Change in Items Offset Within Net Income	(16.5		)
Increase in Consolidated Gross Margin	$	9.6

Consolidated gross margin for items impacting net income increased $26.1 million, which includes the following:

• An increase in South Dakota electric rates;

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

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

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

These increases were partly offset by:

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

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

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

• A decrease in electric retail volumes due primarily to warmer winter weather and colder late summer weather in our Montana jurisdiction, along with lower industrial volumes of a large Montana customer, partly offset by warmer spring and summer weather in our South Dakota jurisdiction and 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 primarily associated with the Beethoven wind generation project, which is a reduction in our customers rates (offset by reduced income tax expense);

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

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

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	Nine Months Ended September 30,
	2016		2015		Change			% Change
	(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative	$	220.7	$	222.1	$	(1.4	)	(0.6	)%
Property and other taxes	111.3		101.0		10.3			10.2
Depreciation and depletion	119.6		107.2		12.4			11.6
	$	451.6	$	430.3	$	21.3		5.0	%

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

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

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

• 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 DSIP related expenses;

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

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

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

These decreases were offset in part by:

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

• 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.

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

43

Property and other taxes were $111.3 million for the nine months ended September 30, 2016, as compared with $101.0 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 $0.8 million decrease from the conveyance of Kerr to the CSKT in September 2015.

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

Consolidated operating income for the nine months ended September 30, 2016 was $181.8 million, as compared with $193.5 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 nine months ended September 30, 2016 was $72.0 million, as compared with $68.1 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, lower capitalization of allowance for funds used during construction (AFUDC), and increased debt outstanding associated with the Beethoven wind project acquisition, partly offset by the debt refinancing transactions discussed above.

Consolidated other income for the nine months ended September 30, 2016, was $4.2 million, as compared with $5.4 million in the same period of 2015. This decrease was primarily due to lower capitalization of AFUDC, partly offset by a $1.8 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).

Consolidated income tax benefit for the nine months ended September 30, 2016 was $4.2 million, as compared with a income tax expense of $24.6 millionin the same period of 2015. Our effective tax rate for the nine months ended September 30, 2016 was (3.7)% as compared with 18.8% for the same period of 2015. The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

	Nine Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	114.0				$	130.8
Income tax calculated at 35% federal statutory rate	39.9			35.0	%	45.8			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(2.7		)	(2.4	)	(0.3		)	(0.3	)
Flow-through repairs deductions	(32.7		)	(28.6	)	(17.2		)	(13.2	)
Production tax credits	(7.3		)	(6.4	)	(2.6		)	(2.0	)
Plant and depreciation of flow through items	(1.4		)	(1.3	)	(1.0		)	(0.8	)
Prior year permanent return to accrual adjustments	(0.1		)	(0.1	)	1.0			0.8
Other, net	0.1			0.1		(1.1		)	(0.7	)
	(44.1		)	(38.7	)	(21.2		)	(16.2	)
	$	(4.2	)	(3.7	)%	$	24.6		18.8	%

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

Consolidated net income for the nine months ended September 30, 2016 was $118.2 million as compared with $106.2 million for the same period in 2015. This increase was primarily due to lower income taxes as discussed above, and improved gross margin, partly offset by the inclusion in our 2015 results of a $20.8 million insurance recovery and higher interest expense.

44

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

	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	219.3	$	208.2	$	11.1		5.3	%
Regulatory amortization	2.3		12.5		(10.2		)	(81.6	)
Total retail revenues	221.6		220.7		0.9			0.4
Transmission	13.4		13.8		(0.4		)	(2.9	)
Ancillary services	0.4		0.4		—			—
Wholesale and other	31.2		3.6		27.6			766.7
Total Revenues	266.6		238.5		28.1			11.8
Total Cost of Sales	89.7		66.2		23.5			35.5
Gross Margin	$	176.9	$	172.3	$	4.6		2.7	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	67,346	$	65,296	559	559	291,628	287,708
South Dakota	16,426		13,376		151	142	50,044	49,811
Residential	83,772		78,672		710	701	341,672	337,519
Montana	88,932		86,942		813	827	65,702	64,873
South Dakota	24,254		20,679		268	259	12,665	12,571
Commercial	113,186		107,621		1,081	1,086	78,367	77,444
Industrial	9,937		10,420		555	558	75	75
Other	12,377		11,455		97	91	8,010	7,952
Total Retail Electric	$	219,272	$	208,168	2,443	2,436	428,124	422,990

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

45

	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	413	340	336	21% colder	23% colder
South Dakota	42	73	83	42% warmer	49% warmer

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

	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota rate increase	$	9.2
Lost revenue adjustment mechanism	(1.8		)
Retail volumes	(0.4		)
Transmission	(0.4		)
Other	0.5
Change in Gross Margin Impacting Net Income	7.1
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(4.3		)
Production tax credits flowed-through trackers	(2.1		)
Property taxes recovered in trackers	3.9
Change in Items Offset Within Net Income	(2.5		)
Increase in Consolidated Gross Margin	$	4.6

Gross margin for items impacting net income increased $7.1 million including the following:

• An increase in South Dakota electric rates; partly offset by

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

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

• 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 primarily associated with the Beethoven wind generation 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. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

46

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

	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	630.0	$	621.9	$	8.1		1.3	%
Regulatory amortization	15.1		23.1		(8.0		)	(34.6	)
Total retail revenues	645.1		645.0		0.1			—
Transmission	38.8		41.1		(2.3		)	(5.6	)
Ancillary services	1.2		1.2		—			—
Wholesale and other	71.3		8.6		62.7			729.1
Total Revenues	756.4		695.9		60.5			8.7
Total Cost of Sales	245.5		196.0		49.5			25.3
Gross Margin	$	510.9	$	499.9	$	11.0		2.2	%

	Revenues				Megawatt Hours (MWH)		Avg. Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	207,080	$	206,284	1,748	1,732	290,807	286,854
South Dakota	44,305		38,031		433	434	49,967	49,774
Residential	251,385		244,315		2,181	2,166	340,774	336,628
Montana	257,566		262,367		2,381	2,401	65,467	64,594
South Dakota	65,454		56,552		749	739	12,591	12,467
Commercial	323,020		318,919		3,130	3,140	78,058	77,061
Industrial	29,626		33,412		1,628	1,697	74	75
Other	25,993		25,250		170	167	6,300	6,252
Total Retail Electric	$	630,024	$	621,896	7,109	7,170	425,206	420,016

	Cooling Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	313	382	316	18% colder	1% colder
South Dakota	837	719	696	16% warmer	20% warmer

	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	4,411	4,328	4,906	2% colder	10% warmer
South Dakota	4,962	5,342	5,631	7% warmer	12% warmer

47

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

	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
South Dakota rate increase	$	27.8
Lost revenue adjustment mechanism	8.2
QF adjustment	6.1
MPSC disallowance	(9.5		)
Transmission	(2.3		)
Retail volumes	(1.1		)
Other	(1.4		)
Change in Gross Margin Impacting Net Income	27.8
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
Hydro operations - Kerr conveyance	(16.0		)
Production tax credits flowed-through trackers	(8.0		)
Property taxes recovered in trackers	7.2
Change in Items Offset Within Net Income	(16.8		)
Increase in Consolidated Gross Margin	$	11.0

Gross margin for items impacting net income increased $27.8 million including the following:

• An increase in South Dakota electric rates;

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

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

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 generation 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).

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.

48

NATURAL GAS SEGMENT

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

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

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

• Wholesale: Primarily represents transportation and storage for others.

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

	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	21.1	$	20.7	$	0.4		1.9	%
Regulatory amortization	3.6		4.0		(0.4		)	(10.0	)
Total retail revenues	24.7		24.7		—			—
Wholesale and other	9.7		9.5		0.2			2.1
Total Revenues	34.4		34.2		0.2			0.6
Total Cost of Sales	6.5		7.4		(0.9		)	(12.2	)
Gross Margin	$	27.9	$	26.8	$	1.1		4.1	%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	9,607	$	9,227	901	832	167,909	165,829
South Dakota	1,699		1,770		108	113	38,907	38,523
Nebraska	1,796		1,886		145	148	36,888	36,662
Residential	13,102		12,883		1,154	1,093	243,704	241,014
Montana	5,691		5,219		623	579	23,108	22,810
South Dakota	1,248		1,397		213	228	6,401	6,225
Nebraska	904		1,026		174	174	4,688	4,599
Commercial	7,843		7,642		1,010	981	34,197	33,634
Industrial	109		130		13	17	257	262
Other	87		66		11	9	157	153
Total Retail Gas	$	21,141	$	20,721	2,188	2,100	278,315	275,063

	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	413	340	336	21% colder	23% colder
South Dakota	42	73	83	42% warmer	49% warmer
Nebraska	22	27	43	19% warmer	49% warmer

49

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

	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Retail volumes	$	1.4
Production	(0.2		)
Other	(0.8		)
Change in Gross Margin Impacting Net Income	0.4
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	0.8
Production gathering fees	(0.1		)
Change in Items Offset Within Net Income	0.7
Increase in Consolidated Gross Margin	$	1.1

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

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

• A decrease in production margin due to lower overhead fees.

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

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

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

Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

50

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

	Results
	2016		2015		Change			% Change
	(dollars in millions)
Retail revenues	$	138.1	$	159.3	$	(21.2	)	(13.3	)%
Regulatory amortization	3.1		3.4		(0.3		)	(8.8	)
Total retail revenues	141.2		162.7		(21.5		)	(13.2	)
Wholesale and other	29.1		30.7		(1.6		)	(5.2	)
Total Revenues	170.3		193.4		(23.1		)	(11.9	)
Total Cost of Sales	47.8		69.5		(21.7		)	(31.2	)
Gross Margin	$	122.5	$	123.9	$	(1.4	)	(1.1	)%

	Revenues				Dekatherms (Dkt)		Customer Counts
	2016		2015		2016	2015	2016	2015
	(in thousands)
Montana	$	60,160	$	64,724	7,622	7,420	167,901	165,801
South Dakota	15,827		19,944		1,982	2,151	39,115	38,770
Nebraska	13,040		16,964		1,703	1,851	37,077	36,894
Residential	89,027		101,632		11,307	11,422	244,093	241,465
Montana	30,673		33,140		4,070	4,003	23,190	22,924
South Dakota	10,200		13,529		1,984	2,096	6,428	6,268
Nebraska	6,850		9,564		1,310	1,414	4,714	4,639
Commercial	47,723		56,233		7,364	7,513	34,332	33,831
Industrial	698		855		98	109	260	263
Other	662		621		103	89	157	152
Total Retail Gas	$	138,110	$	159,341	18,872	19,133	278,842	275,711

	Heating Degree Days			2016 as compared with:
	2016	2015	Historic Average	2015	Historic Average
Montana	4,411	4,328	4,906	2% colder	10% warmer
South Dakota	4,962	5,342	5,631	7% warmer	12% warmer
Nebraska	4,011	4,382	4,630	8% warmer	13% warmer

51

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

	Gross Margin 2016 vs. 2015
	(in millions)
Gross Margin Items Impacting Net Income
Production	$	(1.4	)
Lost revenue adjustment mechanism	0.6
Retail volumes	0.3
Other	(1.2		)
Change in Gross Margin Impacting Net Income	(1.7		)
Gross Margin Items Offset in Operating Expenses
Property taxes recovered in trackers	1.4
Production gathering fees	(1.1		)
Change in Items Offset Within Net Income	0.3
Decrease in Consolidated Gross Margin	$	(1.4	)

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

• A decrease in production margin due to a $0.7 million decrease in interim rates based on actual costs and a $0.7 million decrease in overhead fees; partly offset by

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

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

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

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

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

In addition, average natural gas supply prices decreased in 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.

52

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 maintain a 50 - 55 percent debt to total capital ratio excluding capital leases, and continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

Short-term liquidity is provided by internal cash flows, the sale of commercial paper and use of our revolving credit facility. We utilize our short-term borrowings and/or revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. Short-term borrowings may also be used to temporarily fund utility capital requirements. As of September 30, 2016, our total net liquidity was approximately $132.8 million, including $5.1 million of cash and $127.7 million of revolving credit facility availability. Revolving credit facility availability was $136.2 millionas of October 14, 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. During the third quarter of 2016, the City of Forsyth, Montana, issued on our behalf $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds at a fixed interest rate of 2.00% maturing in 2023. Proceeds from the issuance and available funds were used to redeem the City of Forsyth's 4.65%, $170.2 million Pollution Control Revenue Bonds due 2023. Also during the third quarter of 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes.

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

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

Factors Impacting our Liquidity

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

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

53

As of September 30, 2016, we are under collected on our supply trackers by approximately $5.1 million, as compared with an under collection of $29.4 million as of December 31, 2015, and $15.0 million as of September 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 October 14, 2016, our current ratings with these agencies are as follows:

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

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

Cash Flows

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

	Nine Months Ended September 30,
	2016			2015
Operating Activities
Net income	$	118.2		$	106.2
Non-cash adjustments to net income	117.1			132.2
Changes in working capital	28.9			65.1
Other noncurrent assets and liabilities	(6.2		)	0.9
Cash Provided by Operating Activities	258.0			304.4
Investing Activities
Property, plant and equipment additions	(204.0		)	(203.3		)
Acquisitions	—			(143.3		)
Proceeds from sale of assets	1.4			30.2
Change in restricted cash	—			11.7
Cash Used in Investing Activities	(202.6		)	(304.7		)
Financing Activities
Issuances of long-term debt, net	24.5			120.0
Repayments of short-term borrowings, net	(7.6		)	(49.9		)
Dividends on common stock	(71.8		)	(67.1		)
Financing costs	(6.6		)	(12.1		)
Other	(0.8		)	(0.9		)
Cash Used in Financing Activities	(62.3		)	(10.0		)
Decrease in Cash and Cash Equivalents	$	(6.9	)	$	(10.3	)
Cash and Cash Equivalents, beginning of period	$	12.0		$	20.4
Cash and Cash Equivalents, end of period	$	5.1		$	10.1

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Cash Provided by Operating Activities

As of September 30, 2016, cash and cash equivalents were $5.1 million as compared with $12.0 million at December 31, 2015 and $10.1 million at September 30, 2015. Cash provided by operating activities totaled $258.0 million for the nine months ended September 30, 2016 as compared with $304.4 million during the nine months ended September 30, 2015. This decrease in operating cash flows is primarily due to refunds associated with the DGGS FERC ruling and the South Dakota electric rate case of approximately $30.8 million and $7.2 million, respectively, to customers during the first nine months of 2016, offset in part by improved collections from customers during the prior period.

Cash Used in Investing Activities

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

Cash Used in Financing Activities

Cash used in financing activities totaled $62.3 million during the nine months ended September 30, 2016 as compared with $10.0 million during the nine months ended September 30, 2015. During the nine months ended September 30, 2016, net cash used in financing activities includes the payment of dividends of $71.8 million, the payment of financing costs of $6.6 million, and net repayments of commercial paper of $7.6 million, partially offset by net proceeds from the issuance of debt of $24.5 million. During the nine months ended September 30, 2015, net cash used in financing activities consisted of net repayments of commercial paper of $49.9 million, the payment of dividends of $67.1 million, and the payment of financing costs of $12.1 million, offset in part by net proceeds from the issuance of debt of $120.0 million.

Financing Transactions - 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. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018. In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes. These bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended.

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

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Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 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	$	1,794,519	$	—	$	—	$	—	$	250,000	$	—	$	1,544,519
Capital leases	26,801		476		1,979		2,133		2,298		2,476		17,439
Short-term borrowings	222,311		222,311		—		—		—		—		—
Estimated pension and other postretirement obligations (1)	55,075		906		13,661		13,554		13,489		13,465		N/A
Qualifying facilities liability (2)	900,421		18,393		74,607		76,703		78,836		80,984		570,898
Supply and capacity contracts (3)	1,734,039		61,300		199,378		150,808		146,993		112,364		1,063,196
Contractual interest payments on debt (4)	1,381,518		23,276		80,027		79,850		69,976		62,051		1,066,338
Environmental remediation obligations (1)	6,528		928		1,650		1,650		1,500		800		N/A
Total Commitments (5)	$	6,121,212	$	327,590	$	371,302	$	324,698	$	563,092	$	272,140	$	4,262,390

_________________________

(1) We estimate cash obligations related to our pension and other postretirement benefit programs and environmental remediation obligations for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(2) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $74 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $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 0.96% through maturity.

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

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

As of September 30, 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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%. To more cost effectively meet short-term cash requirements, we 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 September 30, 2016, we had approximately $222.3 million of commercial paper outstanding and no borrowings on our revolving credit facility. A 1% increase in interest rates would increase our annual interest expense by approximately $2.2 million.

Commodity Price Risk

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

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

Counterparty Credit Risk

We are exposed to counterparty credit risk related to the ability of 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.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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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, which, in September 2016, upheld the District Court's decision.

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

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

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

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

In 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. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We 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.

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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 April 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, 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. The rule also would codify the Integrity Verification Process (IVP) which is a process that will require companies to have reliable, traceable, verifiable, and complete records for pipelines in certain areas. The rule would establish a deadline for IVP completion that we will be required to meet. 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, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. We asked the

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

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

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

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.

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

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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.

64

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

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.

65

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

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

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.

66

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 4.1— Indenture, dated as of August 1, 2016, between City of Forsyth, Rosebud County, Montana

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

Exhibit 4.2— Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).

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

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

Exhibit 4.5— Fifteenth Supplemental Indenture, dated as of September 1, 2016, among 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 October 6, 2016, Commission File No. 1-10499).

Exhibit 31.1—Certification of chief executive officer.

Exhibit 31.2—Certification of chief financial officer.

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

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

Exhibit 101.INS—XBRL Instance Document

Exhibit 101.SCH—XBRL Taxonomy Extension Schema Document

67

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

68

SIGNATURES

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

			NorthWestern Corporation
Date:	October 20, 2016	By:	/s/ BRIAN B. BIRD
			Brian B. Bird
			Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

69

EXHIBIT INDEX

Exhibit Number	Description
4.1	Indenture, dated as of August 1, 2016, between City of Forsyth, Rosebud County, Montana  and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.2	Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3	Bond Delivery Agreement, dated as of August 1, 2016, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.4	Thirty-sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.5	Fifteenth Supplemental Indenture, dated as of September 1, 2016, among 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 October 6, 2016, Commission File No. 1-10499).
*31.1	Certification of chief executive officer.
*31.2	Certification of chief financial officer.
*32.1	Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB	XBRL Taxonomy Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

_________________________

* Filed herewith

70

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert C. Rowe, certify that:

1. I have reviewed this report on Form 10-Q of NorthWestern Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

October 20, 2016

/s/ ROBERT C. ROWE

Robert C. Rowe

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Brian B. Bird, certify that:

1. I have reviewed this report on Form 10-Q of NorthWestern Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

October 20, 2016

/s/ BRIAN B. BIRD

Brian B. Bird

Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert C. Rowe, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

October 20, 2016	/s/ ROBERT C. ROWE
	Robert C. Rowe
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of NorthWestern Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian B. Bird, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

October 20, 2016	/s/ BRIAN B. BIRD
	Brian B. Bird
	Vice President and Chief Financial Officer

XML

Document and Document Entity Information - USD ($)	9 Months Ended
	Sep. 30, 2016	Oct. 14, 2016	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	NORTHWESTERN CORPORATION
Entity Central Index Key	0000073088
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		48,327,642
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,046,980,000

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Electric	$ 266,629	$ 238,513	$ 756,374	$ 695,921
Gas	34,369	34,226	170,283	193,389
Total Revenues	300,998	272,739	926,657	889,310
Operating Expenses
Cost of sales	96,156	73,577	293,283	265,495
Operating, general and administrative	68,290	79,296	220,730	222,139
Property and other taxes	40,673	35,712	111,302	100,953
Depreciation and depletion	39,763	35,693	119,551	107,239
Total Operating Expenses	244,882	224,278	744,866	695,826
Operating Income	56,116	48,461	181,791	193,484
Interest Expense, net	(21,049)	(22,043)	(71,979)	(68,101)
Other (Loss) Income	(121)	3,769	4,176	5,429
Income Before Income Taxes	34,946	30,187	113,988	130,812
Income Tax Benefit (Expense)	9,659	(6,389)	4,240	(24,616)
Net Income	$ 44,605	$ 23,798	$ 118,228	$ 106,196
Average Common Shares Outstanding	48,314,783	47,065,082	48,288,678	47,028,924
Basic Earnings per Average Common Share	$ 0.92	$ 0.51	$ 2.45	$ 2.26
Diluted Earnings per Average Common Share	0.92	0.51	2.44	2.25
Dividends Declared per Common Share	$ 0.50	$ 0.48	$ 1.50	$ 1.44

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Comprehensive Income (Loss)
Net Income	$ 44,605	$ 23,798	$ 118,228	$ 106,196
Other comprehensive income (loss), net of tax:
Foreign currency translation	26	233	(84)	445
Cash flow hedges:
Reclassification of net gains on derivative instruments	(1,506)	(555)	(1,432)	(735)
Other comprehensive loss	(1,480)	(322)	(1,516)	(290)
Comprehensive Income	$ 43,125	$ 23,476	$ 116,712	$ 105,906

XML

CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 5,063	$ 11,980
Restricted cash	6,706	6,634
Accounts receivable, net	116,821	154,410
Inventories	54,311	53,458
Regulatory assets	44,501	51,348
Other	10,937	8,830
Total current assets	238,339	286,660
Property, plant, and equipment, net	4,161,993	4,059,499
Goodwill	357,586	357,586
Regulatory assets	592,432	517,223
Other noncurrent assets	43,591	43,727
Total Assets	5,393,941	5,264,695
Current Liabilities:
Current maturities of capital leases	1,942	1,837
Short-term borrowings	222,311	229,874
Accounts payable	57,217	74,511
Accrued expenses	241,185	183,988
Regulatory liabilities	24,159	80,990
Total current liabilities	546,814	571,200
Long-term capital leases	24,859	26,325
Long-term debt	1,794,519	1,768,183
Deferred income taxes	575,812	501,532
Noncurrent regulatory liabilities	392,857	378,711
Other noncurrent liabilities	410,273	418,570
Total Liabilities	3,745,134	3,664,521
Commitments and Contingencies (Note 13)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,956,936 and 48,327,642 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	520	518
Treasury stock at cost	(95,852)	(93,948)
Paid-in capital	1,381,930	1,376,291
Retained earnings	372,321	325,909
Accumulated other comprehensive loss	(10,112)	(8,596)
Total Shareholders' Equity	1,648,807	1,600,174
Total Liabilities and Shareholders' Equity	$ 5,393,941	$ 5,264,695

XML

CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL	Sep. 30, 2016 $ / shares shares
Common Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
Common Stock, Shares Authorized	200,000,000
Common Stock, Shares, Issued	51,956,936
Common Stock, Shares, Outstanding	48,327,642
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
Preferred Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Issued	0
Preferred Stock, Shares Outstanding	0

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
OPERATING ACTIVITIES:
Net Income	$ 118,228	$ 106,196
Items not affecting cash:
Depreciation and depletion	119,551	107,239
Amortization of debt issue costs, discount and deferred hedge gain	907	1,301
Stock-based compensation costs	4,474	3,275
Equity portion of allowance for funds used during construction	(3,053)	(6,568)
Gain on disposition of assets	(15)	(28)
Deferred income taxes	(4,720)	27,019
Changes in current assets and liabilities:
Restricted cash	(72)	(735)
Accounts receivable	37,589	46,025
Inventories	(853)	(3,598)
Other current assets	(2,107)	4,006
Accounts payable	(16,568)	(21,655)
Accrued expenses	60,852	19,307
Regulatory assets	6,847	8,985
Regulatory liabilities	(56,831)	12,739
Other noncurrent assets	(4,234)	(2,240)
Other noncurrent liabilities	(2,007)	3,209
Cash Provided by Operating Activities	257,988	304,477
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(203,998)	(203,324)
Acquisitions	0	(143,328)
Proceeds from sale of assets	1,352	30,209
Change in restricted cash	0	11,758
Cash Used in Investing Activities	(202,646)	(304,685)
FINANCING ACTIVITIES:
Treasury stock activity	(727)	(829)
Dividends on common stock	(71,816)	(67,145)
Issuance of long-term debt	249,660	270,000
Repayments on long-term debt	(225,205)	(150,024)
Repayments of short-term borrowings, net	(7,563)	(49,897)
Financing costs	(6,608)	(12,124)
Cash Used in Financing Activities	(62,259)	(10,019)
Decrease in Cash and Cash Equivalents	(6,917)	(10,227)
Cash and Cash Equivalents, beginning of period	11,980	20,362
Cash and Cash Equivalents, end of period	5,063	10,135
Cash (received) paid during the period for:
Income taxes	(2,922)	27
Interest	56,118	52,106
Significant non-cash transactions:
Capital expenditures included in trade accounts payable	$ 11,803	$ 8,932

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Statement - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Shareholders' Equity [Member]
Balance, shares at Dec. 31, 2014		50,522		3,607
Balance, beginning of period at Dec. 31, 2014		$ 505	$ 1,313,844	$ (92,558)	$ 264,758	$ (8,766)	$ 1,477,783
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	$ 106,196	0	0	0	106,196	0	106,196
Foreign currency translation adjustment	445	0	0	0	0	445	445
Reclassification of net (losses) gains on derivative instruments from OCI to net income, net of tax	$ (735)	$ 0	0	$ 0	0	(735)	(735)
Stock based compensation, shares		166		0
Stock based compensation, value		$ 0	3,304	$ (1,926)	0	0	1,378
Issuance of shares		0
Issuance of shares, value		$ 2			0	0
Adjustments to additional paid in capital, stock issued, issuance costs			469
Stock issued, value, net of fees							924
Issuance of shares, treasury stock				13
Issuance of shares, treasury stock, value				$ 453
Dividends on common stock		0	0	0	(67,145)	0	(67,145)
Dividends per share	$ 1.44
Balance, end of period at Sep. 30, 2015		$ 507	1,317,617	$ (94,031)	303,809	(9,056)	1,518,846
Balance, shares at Sep. 30, 2015		50,688		3,620
Balance, shares at Dec. 31, 2015		51,789		3,617
Balance, beginning of period at Dec. 31, 2015	$ 1,600,174	$ 518	1,376,291	$ (93,948)	325,909	(8,596)	1,600,174
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	118,228	0	0	0	118,228	0	118,228
Foreign currency translation adjustment	(84)	0	0	0	0	(84)	(84)
Reclassification of net (losses) gains on derivative instruments from OCI to net income, net of tax	$ (1,432)	$ 0	0	$ 0	0	(1,432)	(1,432)
Stock based compensation, shares		168		13
Stock based compensation, value		$ 0	5,650	$ (1,904)	0	0	3,746
Issuance of shares		0
Issuance of shares, value		$ 2			0	0
Adjustments to additional paid in capital, stock issued, issuance costs			(11)
Stock issued, value, net of fees							(9)
Issuance of shares, treasury stock				0
Issuance of shares, treasury stock, value
Dividends on common stock		0	0	0	(71,816)	0	(71,816)
Dividends per share	$ 1.50
Balance, end of period at Sep. 30, 2016	$ 1,648,807	$ 520	$ 1,381,930	$ (95,852)	$ 372,321	$ (10,112)	$ 1,648,807
Balance, shares at Sep. 30, 2016		51,957		3,630

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Nature of Operations and Basis of Consolidation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]

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 September 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 $252.9 million through 2024.

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New Accounting Standards

9 Months Ended

Sep. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements [Text Block]

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.

In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows.

Accounting Standards Adopted

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.

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Regulatory Matters

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

Regulatory Matters

Montana Natural Gas Delivery and Production Rate Filing

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

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

Montana Electric and Natural Gas Tracker Filings

Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our 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. The MPSC issued orders 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. In May 2016, we received the final written order in the Consolidated Docket. The written order upheld the March 2016 decision regarding replacement power costs and clarified the disallowance of modeling costs, resulting in a reduction of the disallowance of $0.8 million, which was reflected as a reduction in cost of sales in the second quarter of 2016. Based on the final orders, the impact of the disallowance totals $12.4 million, which includes interest of $2.9 million and is recorded in the Condensed Consolidated Statement of Income for the nine months ended September 30, 2016.

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

Electric and Natural Gas Lost Revenue Adjustment Mechanism- 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 in the second quarter of 2016.

Hydro Compliance Filing

In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. We expect the MPSC to issue a final order during the fourth quarter of 2016. The adjustment to rates is being refunded to customers over 12 months, and as of September 30, 2016, we have deferred revenue remaining of approximately $2.6 million that we expect to refund to customers by the end of 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. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the second half of 2017, at the earliest.

The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of September 30, 2016, the DGGS net property, plant and equipment is approximately $160 million. DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, we are 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.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

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 September 30,
	2016					2015
Income Before Income Taxes	$	34,946				$	30,187
Income tax calculated at 35% federal statutory rate	12,231			35.0	%	10,565			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(615		)	(1.8	)	(857		)	(2.8	)
Flow-through repairs deductions	(18,995		)	(54.4	)	(2,779		)	(9.2	)
Production tax credits	(2,218		)	(6.3	)	(733		)	(2.4	)
Plant and depreciation of flow through items	(243		)	(0.7	)	(374		)	(1.2	)
Prior year permanent return to accrual adjustments	—			—		1,025			3.4
Other, net	181			0.6		(458		)	(1.6	)
	(21,890		)	(62.6	)	(4,176		)	(13.8	)
	$	(9,659	)	(27.6	)%	$	6,389		21.2	%

	Nine Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	113,988				$	130,812
Income tax calculated at 35% federal statutory rate	39,896			35.0	%	45,784			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(2,740		)	(2.4	)	(329		)	(0.3	)
Flow-through repairs deductions	(32,640		)	(28.6	)	(17,240		)	(13.2	)
Production tax credits	(7,317		)	(6.4	)	(2,645		)	(2.0	)
Plant and depreciation of flow through items	(1,427		)	(1.3	)	(1,000		)	(0.8	)
Prior year permanent return to accrual adjustments	(128		)	(0.1	)	1,025			0.8
Other, net	116			0.1		(979		)	(0.7	)
	(44,136		)	(38.7	)	(21,168		)	(16.2	)
	$	(4,240	)	(3.7	)%	$	24,616		18.8	%

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

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

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $90.0 million as of September 30, 2016, including approximately $66.6 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the nine months ended September 30, 2016 we recognized $0.5 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of September 30, 2016, we had $0.5 million of interest accrued in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2015, we did not recognize any expense for interest or penalties, and did not have any amounts accrued 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.

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Goodwill

9 Months Ended

Sep. 30, 2016

Goodwill [Abstract]

Goodwill Disclosure [Text Block]

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 nine months ended September 30, 2016. Goodwill by segment is as follows for both September 30, 2016 and December 31, 2015 (in thousands):

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

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Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2016

Statement of Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

Comprehensive Loss

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

	Three Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	26		$	—	$	26		$	233		$	—	$	233
Reclassification of net gains on derivative instruments	(2,448		)	942		(1,506		)	(901		)	346		(555		)
Other comprehensive loss	$	(2,422	)	$	942	$	(1,480	)	$	(668	)	$	346	$	(322	)

	Nine Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(84	)	$	—	$	(84	)	$	445		$	—	$	445
Reclassification of net gains on derivative instruments	(2,324		)	892		(1,432		)	(1,187		)	452		(735		)
Other comprehensive loss	$	(2,408	)	$	892	$	(1,516	)	$	(742	)	$	452	$	(290	)

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

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

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

		Three Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,940	)	$	(937	)	$	1,245	(8,632		)
Other comprehensive income before reclassifications		—			—			26		26
Amounts reclassified from AOCL	Interest Expense	(1,506		)	—			—		(1,506		)
Net current-period other comprehensive (loss) income		(1,506		)	—			26		(1,480		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271	$	(10,112	)

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

		Nine Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	$	(937	)	$	1,355		(8,596		)
Other comprehensive loss before reclassifications		—			—			(84		)	(84		)
Amounts reclassified from AOCL	Interest Expense	(1,432		)	—			—			(1,432		)
Net current-period other comprehensive loss		(1,432		)	—			(84		)	(1,516		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271		$	(10,112	)

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

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Risk Management and Hedging Activities

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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 September 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):

	Location of amount reclassified from AOCL to Income	Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016
Interest rate contracts	Interest Expense	$	2,324

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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

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)
September 30, 2016
Restricted cash	$	6,350	$	—	$	—	$	—	$	6,350
Rabbi trust investments	25,057		—		—		—		25,057
Total	$	31,407	$	—	$	—	$	—	$	31,407
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):

	September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,794,519	$	1,950,837	$	1,768,183	$	1,844,974

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

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

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Financing Activities

9 Months Ended

Sep. 30, 2016

Financing Activities [Abstract]

Long Term Debt [Text Block]

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. Proceeds were used to redeem our 6.05%, $55 million South Dakota First Mortgage Bonds due 2018. In addition, in September 2016, we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026. Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended.

In August 2016, the City of Forsyth, Rosebud County, Montana issued $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds on our behalf. The bonds were issued at a fixed interest rate of 2.00% maturing in 2023. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and have been used to partially fund the redemption of the 4.65%, $170.2 million City of Forsyth Pollution Control Revenue Refunding Bonds due 2023 (Prior Bonds) issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

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Segment Information

9 Months Ended

Sep. 30, 2016

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

Segment Information

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

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

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

Three Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	266,629			$	34,369		$	—		$	—	$	300,998
Cost of sales	89,681			6,475			—			—		96,156
Gross margin	176,948			27,894			—			—		204,842
Operating, general and administrative	50,460			19,141			(1,311		)	—		68,290
Property and other taxes	32,343			8,328			2			—		40,673
Depreciation and depletion	32,549			7,206			8			—		39,763
Operating income (loss)	61,596			(6,781		)	1,301			—		56,116
Interest expense	(19,099		)	(1,249		)	(701		)	—		(21,049		)
Other income (loss)	982			345			(1,448		)	—		(121		)
Income tax benefit	7,946			1,169			544			—		9,659
Net income (loss)	$	51,425		$	(6,516	)	$	(304	)	$	—	$	44,605
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	66,322		$	16,430		$	—		—		$	82,752

Three Months Ended
September 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	238,513		$	34,226		$	—		$	—	$	272,739
Cost of sales	66,197			7,380			—			—		73,577
Gross margin	172,316			26,846			—			—		199,162
Operating, general and administrative	58,298			19,843			1,155			—		79,296
Property and other taxes	28,648			7,062			2			—		35,712
Depreciation and depletion	28,476			7,209			8			—		35,693
Operating income (loss)	56,894			(7,268		)	(1,165		)	—		48,461
Interest expense	(19,078		)	(2,562		)	(403		)	—		(22,043		)
Other income	1,832			507			1,430			—		3,769
Income tax (expense) benefit	(6,553		)	1,883			(1,719		)	—		(6,389		)
Net income (loss)	$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798
Total assets	$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078
Capital expenditures	$	57,813		$	14,341		$	—		$	—	$	72,154

Nine Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	756,374		$	170,283		$	—		$	—	$	926,657
Cost of sales	245,470			47,813			—			—		293,283
Gross margin	510,904			122,470			—			—		633,374
Operating, general and administrative	157,471			61,638			1,621			—		220,730
Property and other taxes	87,094			24,200			8			—		111,302
Depreciation and depletion	97,614			21,913			24			—		119,551
Operating income (loss)	168,725			14,719			(1,653		)	—		181,791
Interest expense	(65,273		)	(5,018		)	(1,688		)	—		(71,979		)
Other income	2,136			925			1,115			—		4,176
Income tax benefit (expense)	3,600			(574		)	1,214			—		4,240
Net income (loss)	$	109,188		$	10,052		$	(1,012	)	$	—	$	118,228
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	165,885		$	38,113		$	—		—		$	203,998

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

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Earnings Per Share

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

	Three Months Ended
	September 30, 2016	September 30, 2015
Basic computation	48,314,783	47,065,082
Dilutive effect of:
Performance share awards (1)	154,537	245,463
Diluted computation	48,469,320	47,310,545

	Nine Months Ended
	September 30, 2016	September 30, 2015
Basic computation	48,288,678	47,028,924
Dilutive effect of:
Performance share awards (1)	154,889	245,460
Diluted computation	48,443,567	47,274,384

______________

(1)          Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Employee Benefit Plans

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

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

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	8,819			$	9,272		$	369		$	395
Interest cost	19,658			19,631			596			590
Expected return on plan assets	(21,186		)	(23,671		)	(782		)	(727		)
Amortization of prior service cost	185			185			(1,412		)	(1,412		)
Recognized actuarial loss	7,416			7,976			236			289
Net Periodic Benefit Cost (Income)	$	14,892		$	13,393		$	(993	)	$	(865	)

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

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 September 30, 2016, we have a reserve of approximately $30.3 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

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

Manufactured Gas Plants - Approximately $23.7 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of September 30, 2016, the reserve for remediation costs at this site is approximately $11.1 million, and we estimate that approximately $6.5 million of this amount will be incurred during the next five years.

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

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

An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. The additional investigation work began in December 2015 and has continued in 2016. The result of the additional investigation work may lead to the development of site-specific risk-based remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide (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 were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The initial performance period for compliance under the CPP would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program 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 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, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing all four of the generating units that comprise the Colstrip facility in southeast Montana as a scenario for complying with the federal 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, and on September 27, 2016, the Court held oral argument in the matter. An initial ruling on the challenge is not expected until early 2017, and the U.S. Supreme Court decision on challenges to the CPP is not anticipated until mid-2017, if not early 2018.

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

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

Requirements to reduce GHG emissions 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 (MEIC), and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. 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, did not 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. In 2016, Coyote completed installation of control equipment to maintain compliance with the lower NOx emissions of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown. The cost of the control equipment was 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 of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4.

On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief 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. After filing the Second Amended Complaint, Plaintiffs indicated that they were no longer pursuing a number of claims and projects thereby reducing their total to eight claims 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.

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

The consent decree gave the Plaintiffs and Defendants each the right to seek recovery of attorneys’ fees and costs from the other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. While we cannot predict an outcome on the opposing motions seeking attorneys’ fees and costs, we do not anticipate that the outcome will have a significant impact on our results of operations or cash flows.

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, ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $65.6 million. We dispute 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, as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan and Morony facilities on the Missouri-Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

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

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

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

On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court), and Talen consented to our removal. On April 27, 2016, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with the Great Falls Reach in light of the United States Supreme Court’s decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment.

On May 19, 2016, the State asked the Federal District Court to remand the case back to the State District Court. The parties have fully briefed the issue and we have requested oral argument. Talen’s and our motions to dismiss, the State’s motions for remand and our request for oral argument, remain pending before the Federal District Court.

We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If, on remand, the Federal District Court (or the State District Court if the case is remanded back to it) determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $7.0 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Other Legal Proceedings

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

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Nature of Operations and Basis of Consolidation (Policies)

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Variable Interest Entity [Policy Text Block]

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 $252.9 million through 2024.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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 September 30,
	2016					2015
Income Before Income Taxes	$	34,946				$	30,187
Income tax calculated at 35% federal statutory rate	12,231			35.0	%	10,565			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(615		)	(1.8	)	(857		)	(2.8	)
Flow-through repairs deductions	(18,995		)	(54.4	)	(2,779		)	(9.2	)
Production tax credits	(2,218		)	(6.3	)	(733		)	(2.4	)
Plant and depreciation of flow through items	(243		)	(0.7	)	(374		)	(1.2	)
Prior year permanent return to accrual adjustments	—			—		1,025			3.4
Other, net	181			0.6		(458		)	(1.6	)
	(21,890		)	(62.6	)	(4,176		)	(13.8	)
	$	(9,659	)	(27.6	)%	$	6,389		21.2	%

	Nine Months Ended September 30,
	2016					2015
Income Before Income Taxes	$	113,988				$	130,812
Income tax calculated at 35% federal statutory rate	39,896			35.0	%	45,784			35.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	(2,740		)	(2.4	)	(329		)	(0.3	)
Flow-through repairs deductions	(32,640		)	(28.6	)	(17,240		)	(13.2	)
Production tax credits	(7,317		)	(6.4	)	(2,645		)	(2.0	)
Plant and depreciation of flow through items	(1,427		)	(1.3	)	(1,000		)	(0.8	)
Prior year permanent return to accrual adjustments	(128		)	(0.1	)	1,025			0.8
Other, net	116			0.1		(979		)	(0.7	)
	(44,136		)	(38.7	)	(21,168		)	(16.2	)
	$	(4,240	)	(3.7	)%	$	24,616		18.8	%

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2016

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by segment is as follows for both September 30, 2016 and December 31, 2015 (in thousands):

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

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Comprehensive Income (Loss) Comprehensive Income Loss (Tables)

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Comprehensive Income (Loss) [Table Text Block]

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

	Three Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	26		$	—	$	26		$	233		$	—	$	233
Reclassification of net gains on derivative instruments	(2,448		)	942		(1,506		)	(901		)	346		(555		)
Other comprehensive loss	$	(2,422	)	$	942	$	(1,480	)	$	(668	)	$	346	$	(322	)

	Nine Months Ended
	September 30, 2016								September 30, 2015
	Before-Tax Amount			Tax Expense		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit		Net-of-Tax Amount
Foreign currency translation adjustment	$	(84	)	$	—	$	(84	)	$	445		$	—	$	445
Reclassification of net gains on derivative instruments	(2,324		)	892		(1,432		)	(1,187		)	452		(735		)
Other comprehensive loss	$	(2,408	)	$	892	$	(1,516	)	$	(742	)	$	452	$	(290	)

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Comprehensive Income (Loss) Classification Accumulated Other Comprehensive (Income) Loss (Tables)

9 Months Ended

Sep. 30, 2016

Statement of Financial Position [Abstract]

Accumulated Other Comprehensive Income [Table Text Block]

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

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

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

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

		Three Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation		Total
Beginning balance		$	(8,940	)	$	(937	)	$	1,245	(8,632		)
Other comprehensive income before reclassifications		—			—			26		26
Amounts reclassified from AOCL	Interest Expense	(1,506		)	—			—		(1,506		)
Net current-period other comprehensive (loss) income		(1,506		)	—			26		(1,480		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271	$	(10,112	)

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

		Nine Months Ended
		September 30, 2016
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges			Pension and Postretirement Medical Plans			Foreign Currency Translation			Total
Beginning balance		$	(9,014	)	$	(937	)	$	1,355		(8,596		)
Other comprehensive loss before reclassifications		—			—			(84		)	(84		)
Amounts reclassified from AOCL	Interest Expense	(1,432		)	—			—			(1,432		)
Net current-period other comprehensive loss		(1,432		)	—			(84		)	(1,516		)
Ending balance		$	(10,446	)	$	(937	)	$	1,271		$	(10,112	)

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

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Risk Management and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands):

	Location of amount reclassified from AOCL to Income	Amount Reclassified from AOCL into Income during the Nine Months Ended September 30, 2016
Interest rate contracts	Interest Expense	$	2,324

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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)
September 30, 2016
Restricted cash	$	6,350	$	—	$	—	$	—	$	6,350
Rabbi trust investments	25,057		—		—		—		25,057
Total	$	31,407	$	—	$	—	$	—	$	31,407
December 31, 2015
Restricted cash	$	6,240	$	—	$	—	$	—	$	6,240
Rabbi trust investments	24,245		—		—		—		24,245
Total	$	30,485	$	—	$	—	$	—	$	30,485

Fair Value Financial Instruments [Table Text Block]

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

	September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities:
Long-term debt	$	1,794,519	$	1,950,837	$	1,768,183	$	1,844,974

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

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

Three Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	266,629			$	34,369		$	—		$	—	$	300,998
Cost of sales	89,681			6,475			—			—		96,156
Gross margin	176,948			27,894			—			—		204,842
Operating, general and administrative	50,460			19,141			(1,311		)	—		68,290
Property and other taxes	32,343			8,328			2			—		40,673
Depreciation and depletion	32,549			7,206			8			—		39,763
Operating income (loss)	61,596			(6,781		)	1,301			—		56,116
Interest expense	(19,099		)	(1,249		)	(701		)	—		(21,049		)
Other income (loss)	982			345			(1,448		)	—		(121		)
Income tax benefit	7,946			1,169			544			—		9,659
Net income (loss)	$	51,425		$	(6,516	)	$	(304	)	$	—	$	44,605
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	66,322		$	16,430		$	—		—		$	82,752

Three Months Ended
September 30, 2015	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	238,513		$	34,226		$	—		$	—	$	272,739
Cost of sales	66,197			7,380			—			—		73,577
Gross margin	172,316			26,846			—			—		199,162
Operating, general and administrative	58,298			19,843			1,155			—		79,296
Property and other taxes	28,648			7,062			2			—		35,712
Depreciation and depletion	28,476			7,209			8			—		35,693
Operating income (loss)	56,894			(7,268		)	(1,165		)	—		48,461
Interest expense	(19,078		)	(2,562		)	(403		)	—		(22,043		)
Other income	1,832			507			1,430			—		3,769
Income tax (expense) benefit	(6,553		)	1,883			(1,719		)	—		(6,389		)
Net income (loss)	$	33,095		$	(7,440	)	$	(1,857	)	$	—	$	23,798
Total assets	$	4,169,423		$	1,057,919		$	7,736		$	—	$	5,235,078
Capital expenditures	$	57,813		$	14,341		$	—		$	—	$	72,154

Nine Months Ended
September 30, 2016	Electric			Gas			Other			Eliminations		Total
Operating revenues	$	756,374		$	170,283		$	—		$	—	$	926,657
Cost of sales	245,470			47,813			—			—		293,283
Gross margin	510,904			122,470			—			—		633,374
Operating, general and administrative	157,471			61,638			1,621			—		220,730
Property and other taxes	87,094			24,200			8			—		111,302
Depreciation and depletion	97,614			21,913			24			—		119,551
Operating income (loss)	168,725			14,719			(1,653		)	—		181,791
Interest expense	(65,273		)	(5,018		)	(1,688		)	—		(71,979		)
Other income	2,136			925			1,115			—		4,176
Income tax benefit (expense)	3,600			(574		)	1,214			—		4,240
Net income (loss)	$	109,188		$	10,052		$	(1,012	)	$	—	$	118,228
Total assets	$	4,294,549		$	1,093,333		$	6,059		—		$	5,393,941
Capital expenditures	$	165,885		$	38,113		$	—		—		$	203,998

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

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Schedule of Weighted Average Number of Shares [Table Text Block]

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

	Three Months Ended
	September 30, 2016	September 30, 2015
Basic computation	48,314,783	47,065,082
Dilutive effect of:
Performance share awards (1)	154,537	245,463
Diluted computation	48,469,320	47,310,545

	Nine Months Ended
	September 30, 2016	September 30, 2015
Basic computation	48,288,678	47,028,924
Dilutive effect of:
Performance share awards (1)	154,889	245,460
Diluted computation	48,443,567	47,274,384

______________

(1)          Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

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

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Components of Net Periodic Benefit Cost (Income)
Service cost	8,819			$	9,272		$	369		$	395
Interest cost	19,658			19,631			596			590
Expected return on plan assets	(21,186		)	(23,671		)	(782		)	(727		)
Amortization of prior service cost	185			185			(1,412		)	(1,412		)
Recognized actuarial loss	7,416			7,976			236			289
Net Periodic Benefit Cost (Income)	$	14,892		$	13,393		$	(993	)	$	(865	)

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Nature of Operations and Basis of Consolidation (Details) $ in Millions	Sep. 30, 2016 USD ($) watts	Dec. 31, 2015 customers
Number of customers | customers		701,000
Number of megawatts of qualifying facility | watts	35
Estimated aggregate gross contractual payments for qualifying facilities through 2024 | $	$ 252.9

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New Accounting Standards Accounting Standards Adopted (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
Debt issuance costs reclassified as adjustments to carrying cost of debt	$ 13.9	$ 13.0

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Regulatory Matters (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	41 Months Ended
	Jun. 30, 2016	Sep. 30, 2016	Nov. 30, 2015	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Property, plant and equipment, net		$ 4,161,993			$ 4,059,499
Montana Natural Gas Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate increase		10,900
Requested rate increase for delivery service		7,400
Requested rate increase for production		$ 3,500
Requested return on equity, percentage		10.35%
Public utilities rate base		$ 432,100
Requested debt capital structure, percentage		53.00%
Requested equity capital structure, percentage		47.00%
Interim rate increase		$ 5,600
Hydro Transaction [Member] | Revenue Subject to Refund [Member]
Public Utilities, General Disclosures [Line Items]
Deferred revenue, current		2,600
Demand side management [Member]
Public Utilities, General Disclosures [Line Items]
Demand side management revenue recognized annually			$ 7,100
Deferred revenue recognized	$ 14,200
Deferred revenue					$ 14,200
Dave Gates Generating Station [Member]
Public Utilities, General Disclosures [Line Items]
Deferred revenue, refund payments	27,300
Property, plant and equipment, net		160,000
Disallowed Expenses [Member]
Public Utilities, General Disclosures [Line Items]
Disallowed replacement power costs				$ 8,200
Disallowed costs		12,400		10,300
Disallowed interest costs		$ 2,900
Disallowed modeling costs				$ 2,100
Disallowed modeling cost reduction	$ 800

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Income tax benefit	$ 15.5
Tax benefit related to prior years	12.5
Unrecognized tax benefit more likely than not percentage threshold		50.00%
Unrecognized tax benefits	90.0	$ 90.0
Unrecognized tax benefits that would impact effective tax rate	66.6	66.6
Interest expense or penalties, uncertain tax positions		0.5	$ 0.0
Accrued interest, uncertain tax positions	$ 0.5	$ 0.5	$ 0.0	$ 0.0
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Earliest year subject to examination		2000

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Income Taxes Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Effective tax rate reconciliation
Income Before Income Taxes	$ 34,946	$ 30,187	$ 113,988	$ 130,812
Income tax calculated at 35% federal statutory rate	$ 12,231	$ 10,565	$ 39,896	$ 45,784
Income tax calculated at 35% federal statutory rate	35.00%	35.00%	35.00%	35.00%
State income, net of federal provisions	$ (615)	$ (857)	$ (2,740)	$ (329)
State income, net of federal provisions	(1.80%)	(2.80%)	(2.40%)	(0.30%)
Flow-through repairs deductions	$ (18,995)	$ (2,779)	$ (32,640)	$ (17,240)
Flow-through repairs deductions	(54.40%)	(9.20%)	(28.60%)	(13.20%)
Production tax credits	$ (2,218)	$ (733)	$ (7,317)	$ (2,645)
Production tax credits	(6.30%)	(2.40%)	(6.40%)	(2.00%)
Plant and depreciation of flow through items	$ (243)	$ (374)	$ (1,427)	$ (1,000)
Plant and depreciation of flow through items	(0.70%)	(1.20%)	(1.30%)	(0.80%)
Prior year permanent return to accrual adjustments	$ 0	$ 1,025	$ (128)	$ 1,025
Prior year permanent return to accrual adjustments	0.00%	3.40%	(0.10%)	0.80%
Other, net	$ 181	$ (458)	$ 116	$ (979)
Other, net	0.60%	(1.60%)	0.10%	(0.70%)
Total Other Reconciling Items	$ (21,890)	$ (4,176)	$ (44,136)	$ (21,168)
Total Other Reconciling Items	(62.60%)	(13.80%)	(38.70%)	(16.20%)
Income Tax Expense	$ (9,659)	$ 6,389	$ (4,240)	$ 24,616
Income Tax Expense	(27.60%)	21.20%	(3.70%)	18.80%
Internal Revenue Service (IRS) [Member]
Effective tax rate reconciliation
Income tax calculated at 35% federal statutory rate			35.00%

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Goodwill (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Goodwill [Line Items]
Change in goodwill	$ 0
Goodwill	357,586	$ 357,586
Electric [Member]
Goodwill [Line Items]
Goodwill	243,558	243,558
Natural gas [Member]
Goodwill [Line Items]
Goodwill	$ 114,028	$ 114,028

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Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	$ 26	$ 233	$ (84)	$ 445
Reclassification of net gains on derivative instruments	(2,448)	(901)	(2,324)	(1,187)
Other comprehensive loss	(2,422)	(668)	(2,408)	(742)
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0	0
Reclassification of net gains on derivative instruments	942	346	892	452
Other comprehensive loss	942	346	892	452
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment	26	233	(84)	445
Reclassification of net gains on derivative instruments	(1,506)	(555)	(1,432)	(735)
Other comprehensive loss	$ (1,480)	$ (322)	$ (1,516)	$ (290)

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Comprehensive Income (Loss) Balance sheet classification (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Foreign currency translation	$ 1,271	$ 1,355
Derivative instruments designated as cash flow hedges	(10,446)	(9,014)
Pension and postretirement medical plans	(937)	(937)
Accumulated other comprehensive loss	$ (10,112)	$ (8,596)

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Comprehensive Income (Loss) Changes in AOCI by Component (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance			$ (8,596)
Net current-period other comprehensive (loss) income	$ (1,480)	$ (322)	(1,516)	$ (290)
Ending balance	(10,112)		(10,112)
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(8,940)	(8,496)	(9,014)	(8,316)
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI, Interest expense	(1,506)	(555)	(1,432)	(735)
Net current-period other comprehensive (loss) income	(1,506)	(555)	(1,432)	(735)
Ending balance	(10,446)	(9,051)	(10,446)	(9,051)
Pension and Postretirement Medical Plans
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(937)	(1,247)	(937)	(1,247)
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI, Interest expense	0	0	0	0
Net current-period other comprehensive (loss) income	0	0	0	0
Ending balance	(937)	(1,247)	(937)	(1,247)
Foreign Currency Translation
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	1,245	1,009	1,355	797
Other comprehensive income before reclassifications	26	233	(84)	445
Amounts reclassified from AOCI, Interest expense	0	0	0	0
Net current-period other comprehensive (loss) income	26	233	(84)	445
Ending balance	1,271	1,242	1,271	1,242
Total
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(8,632)	(8,734)	(8,596)	(8,766)
Other comprehensive income before reclassifications	26	233	(84)	445
Amounts reclassified from AOCI, Interest expense	(1,506)	(555)	(1,432)	(735)
Net current-period other comprehensive (loss) income	(1,480)	(322)	(1,516)	(290)
Ending balance	$ (10,112)	$ (9,056)	$ (10,112)	$ (9,056)

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Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Pre-tax gain on cash flow hedges remaining in AOCL	$ 17,200
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCL to interest expense	600
Physical purchase and sale of gas and electricity at fixed prices	$ 0	$ 0
Number of interest rate derivatives held	0
Interest Expense [Member]
Derivative [Line Items]
Amount of gain reclassified from AOCL	$ 2,324

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Fair Value Recurring Basis (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair value, assets, level 1 to level 2 transfers, amount	$ 0	$ 0
Fair value, assets, level 2 to level 1 transfers, amount	0	0
Fair value, liabilities, level 1 to level 2 transfers, amount	0	0
Fair value, liabilities, level 2 to level 1 transfers, amount	0	0
Fair Value, transfers into (out of) level 3	0	0
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	6,350	6,240
Rabbi trust investments	25,057	24,245
Total	31,407	30,485
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs(Level 2)
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	0	0
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs(Level 3)
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	0	0
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	6,350	6,240
Rabbi trust investments	25,057	24,245
Total	31,407	30,485
Margin Cash Collateral Offset | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	$ 0	$ 0

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Fair Value Measurements Fair Value Finanical Insruments (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	$ 1,794,519	$ 1,768,183
Long-term debt, fair value	$ 1,950,837	$ 1,844,974

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Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended	9 Months Ended
	Jun. 30, 2016	Sep. 30, 2016
Debt Instrument [Line Items]
Debt Issued By Third Party		$ 144.7
Secured Debt [Member] | Secured Debt South Dakota Due June 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	$ 60.0
Interest rate	2.80%
Maturity date	Jun. 15, 2026
Secured Debt [Member] | Secured Debt South Dakota Due 2018 [Member]
Debt Instrument [Line Items]
Interest rate	6.05%
Maturity date	May 01, 2018
Debt instrument, repurchased face amount	$ 55.0
Secured Debt [Member] | Secured Debt Montana Due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		$ 144.7
Interest rate		2.00%
Maturity date		Aug. 01, 2023
Secured Debt [Member] | Repurchased Secured Debt Montana Due 2023 [Member]
Debt Instrument [Line Items]
Interest rate		4.65%
Maturity date		Aug. 01, 2023
Debt instrument, repurchased face amount		$ 170.2
Secured Debt [Member] | Secured Debt South Dakota Due September 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		$ 45.0
Interest rate		2.66%
Maturity date		Sep. 01, 2026

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Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 300,998	$ 272,739	$ 926,657	$ 889,310
Cost of sales	96,156	73,577	293,283	265,495
Gross margin	204,842	199,162	633,374	623,815
Operating, general and administrative	68,290	79,296	220,730	222,139
Property and other taxes	40,673	35,712	111,302	100,953
Depreciation and depletion	39,763	35,693	119,551	107,239
Operating income (loss)	56,116	48,461	181,791	193,484
Interest expense	(21,049)	(22,043)	(71,979)	(68,101)
Other income (loss)	(121)	3,769	4,176	5,429
Income Tax Benefit (Expense)	9,659	(6,389)	4,240	(24,616)
Net Income	44,605	23,798	118,228	106,196
Total assets	5,393,941	5,235,078	5,393,941	5,235,078	$ 5,264,695
Capital expenditures	82,752	72,154	203,998	203,324
Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	266,629	238,513	756,374	695,921
Cost of sales	89,681	66,197	245,470	196,034
Gross margin	176,948	172,316	510,904	499,887
Operating, general and administrative	50,460	58,298	157,471	179,191
Property and other taxes	32,343	28,648	87,094	78,987
Depreciation and depletion	32,549	28,476	97,614	85,523
Operating income (loss)	61,596	56,894	168,725	156,186
Interest expense	(19,099)	(19,078)	(65,273)	(58,524)
Other income (loss)	982	1,832	2,136	4,773
Income Tax Benefit (Expense)	7,946	(6,553)	3,600	(16,364)
Net Income	51,425	33,095	109,188	86,071
Total assets	4,294,549	4,169,423	4,294,549	4,169,423
Capital expenditures	66,322	57,813	165,885	171,800
Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	34,369	34,226	170,283	193,389
Cost of sales	6,475	7,380	47,813	69,461
Gross margin	27,894	26,846	122,470	123,928
Operating, general and administrative	19,141	19,843	61,638	63,554
Property and other taxes	8,328	7,062	24,200	21,958
Depreciation and depletion	7,206	7,209	21,913	21,691
Operating income (loss)	(6,781)	(7,268)	14,719	16,725
Interest expense	(1,249)	(2,562)	(5,018)	(8,304)
Other income (loss)	345	507	925	1,349
Income Tax Benefit (Expense)	1,169	1,883	(574)	(1,621)
Net Income	(6,516)	(7,440)	10,052	8,149
Total assets	1,093,333	1,057,919	1,093,333	1,057,919
Capital expenditures	16,430	14,341	38,113	31,524
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of sales	0	0	0	0
Gross margin	0	0	0	0
Operating, general and administrative	(1,311)	1,155	1,621	(20,606)
Property and other taxes	2	2	8	8
Depreciation and depletion	8	8	24	25
Operating income (loss)	1,301	(1,165)	(1,653)	20,573
Interest expense	(701)	(403)	(1,688)	(1,273)
Other income (loss)	(1,448)	1,430	1,115	(693)
Income Tax Benefit (Expense)	544	(1,719)	1,214	(6,631)
Net Income	(304)	(1,857)	(1,012)	11,976
Total assets	6,059	7,736	6,059	7,736
Capital expenditures	0	0	0	0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of sales	0	0	0	0
Gross margin	0	0	0	0
Operating, general and administrative	0	0	0	0
Property and other taxes	0	0	0	0
Depreciation and depletion	0	0	0	0
Operating income (loss)	0	0	0	0
Interest expense	0	0	0	0
Other income (loss)	0	0	0	0
Income Tax Benefit (Expense)	0	0	0	0
Net Income	0	0	0	0
Total assets	0	0	0	0
Capital expenditures	$ 0	$ 0	$ 0	$ 0

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Earnings Per Share (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Basic computation	48,314,783	47,065,082	48,288,678	47,028,924
Dilutive effect of performance share awards (1)	154,537	245,463	154,889	245,460
Diluted computation	48,469,320	47,310,545	48,443,567	47,274,384

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Employee Benefit Plans Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	$ 2,939	$ 3,091	$ 8,819	$ 9,272
Interest cost	6,553	6,544	19,658	19,631
Expected return on plan assets	(7,062)	(7,890)	(21,186)	(23,671)
Amortization of prior service cost	62	62	185	185
Recognized actuarial loss	2,472	2,659	7,416	7,976
Net Periodic Benefit Cost (Income)	4,964	4,466	14,892	13,393
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	123	132	369	395
Interest cost	198	197	596	590
Expected return on plan assets	(261)	(242)	(782)	(727)
Amortization of prior service cost	(471)	(471)	(1,412)	(1,412)
Recognized actuarial loss	78	96	236	289
Net Periodic Benefit Cost (Income)	$ (333)	$ (288)	$ (993)	$ (865)

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Commitments and Contingencies Environmental (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)	Jul. 01, 2018
Colstrip Unit 4 [Member]
Jointly owned utility plant ownership percentage	30.00%
Environmental obligation, estimated capital Expenditures	$ 90.0
Coyote Generating Facility [Member]
Jointly owned utility plant ownership percentage	10.00%
Environmental remediation obligations [Member]
Environmental remediation obligation, minimum	$ 27.0
Environmental remediation obligation, maximum	32.0
Accrual for environmental loss contingencies	30.3
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	23.7
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	11.1
Environmental remediation obligation next 5 years	$ 6.5
Number of years for environmental remediation obligation to be incurred	5 years
Scenario, Forecast [Member] | Coyote Generating Facility [Member]
NOx emissions per million Btu as calculated on a 30 day rolling average basis		0.5

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Commitments and Contingencies Litigation (Details) - Refinery outage [Member] - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Aug. 31, 2014	Sep. 30, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Damages sought	$ 48.5	$ 65.6	$ 61.7
Retention amount	$ 2.0