UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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

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

Large accelerated filer ý

Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 ý.

Index



		Page

Definitions		3

Forward-Looking Statements		5

Introduction		5

Part I -- Financial Information

Item 1	Financial Statements
	Consolidated Statements of Income -- Three and Nine Months Ended ~~March 31,~~September 30, 2017 and 2016	6

	Consolidated Statements of Comprehensive Income -- Three and Nine Months Ended ~~March 31,~~September 30, 2017 and 2016	7

	Consolidated Balance Sheets -- ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016	8

	Consolidated Statements of Cash Flows -- ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2017 and 2016	9

	Notes to Consolidated Financial Statements	10

Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations	3031

Item 3	Quantitative and Qualitative Disclosures About Market Risk	4144

Item 4	Controls and Procedures	4144

Part II -- Other Information

Item 1	Legal Proceedings	4144

Item 1A	Risk Factors	41

~~Item 2~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	4244

Item 4	Mine Safety Disclosures	4244

Item 5	Other Information	4244

Item 6	Exhibits	4244

Signatures		4345

Exhibit Index		4446

Exhibits

Definitions

The following abbreviations and acronyms used in this Form 10-Q are defined below:



Abbreviation or Acronym
2016 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2016
AFUDC	Allowance for funds used during construction
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
ATBs	Atmospheric tower bottoms
Brazilian Transmission Lines	Company's former investment in companies owning three electric transmission lines in Brazil
Calumet	Calumet Specialty Products Partners, L.P.
Capital Electric	Capital Electric Construction Company, Inc., a direct wholly owned subsidiary of MDU Construction Services
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Company	MDU Resources Group, Inc.
Coyote Creek	Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station	427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery	20,000-barrel-per-day diesel topping plant built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining	Dakota Prairie Refining, LLC, a limited liability company previously owned by WBI Energy and Calumet (previously included in the Company's refining segment)
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings (previously referred to as the Company's exploration and production segment)
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
IFRS	International Financial Reporting Standards
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC	Idaho Public Utilities Commission
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest	Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
kWh	Kilowatt-hour
LWG	Lower Willamette Group
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
MDU Construction Services	MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital	MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MISO	Midcontinent Independent System Operator, Inc.
MMdk	Million dk
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
~~Montana Seventeenth Judicial District Court~~	~~Montana Seventeenth Judicial District Court, Phillips County~~
MTPSC	Montana Public Service Commission
MW	~~Megawatt~~



MW	Megawatt
NDPSC	North Dakota Public Service Commission
~~Omimex~~	~~Omimex Canada, Ltd.~~
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
Pronghorn	Natural gas processing plant located near Belfield, North Dakota (WBI Energy Midstream's 50 percent ownership interests were sold effective January 1, 2017)
PRP	Potentially Responsible Party
RIN	Renewable Identification Number
ROD	Record of Decision
SEC	United States Securities and Exchange Commission
~~Securities Act~~SSIP	~~Securities Act of 1933, as amended~~System Safety and Integrity Program
Tesoro	Tesoro Refining & Marketing Company LLC
Tesoro Logistics	QEP Field Services, LLC doing business as Tesoro Logistics Rockies LLC
~~United States District Court for the District of Montana~~	~~United States District Court for the District of Montana, Great Falls Division~~
VIE	Variable interest entity
Washington DOE	Washington State Department of Ecology
WBI Energy	WBI Energy, Inc., ~~an indirect~~a direct wholly owned subsidiary of WBI Holdings
WBI Energy Midstream	WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Transmission	WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC	Washington Utilities and Transportation Commission
~~WYPSC~~	~~Wyoming Public Service Commission~~

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are ~~other than~~not statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Part I, Item 2 - MD&A - Prospective Information.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements reported in Part I, Item 1A - Risk Factors in the 2016 Annual Report and subsequent filings with the SEC.

Introduction

The Company is a regulated energy delivery and construction materials and services business, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, Great Plains, Cascade and Intermountain comprise the natural gas distribution segment. Montana-Dakota also comprises the electric segment.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings, Knife River, MDU Construction Services, Centennial Resources and Centennial Capital. WBI Holdings is comprised of the pipeline and midstream segment and Fidelity, formerly the Company's exploration and production business. Knife River is the construction materials and contracting segment, MDU Construction Services is the construction services segment, and Centennial Resources and Centennial Capital are both reflected in the Other category.

For more information on the Company's business segments and discontinued operations, see Notes 8 and 13.

Part I -- Financial Information

Item 1. Financial Statements

MDU Resources Group, Inc.

Consolidated Statements of Income

(Unaudited)


	Three Months Ended					Three Months Ended						Nine Months Ended
	March 31,					September 30,
	2017		2016			2017			2016			2017			2016
	(In thousands, except per share amounts)					(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream	$	433,614	$	385,865		$	206,936		$	192,079		$	866,035		$	783,997
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	504,311		474,349			1,065,612			1,016,488			2,412,077			2,328,733
Total operating revenues	937,925		860,214			1,272,548			1,208,567			3,278,112			3,112,730
Operating expenses:
Fuel and purchased power	21,886		22,011
Purchased natural gas sold	192,948		161,035
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream	78,738		74,625			79,293			77,662			235,306			229,364
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	478,478		442,500			893,616			842,878			2,115,747			2,008,122
Total operation and maintenance						972,909			920,540			2,351,053			2,237,486
Electric fuel and purchased power						18,906			16,800			57,544			54,725
Purchased natural gas sold						33,319			34,321			283,936			242,795
Depreciation, depletion and amortization	51,325		54,884			52,155			54,094			155,138			163,226
Taxes, other than income	47,438		43,174			38,882			36,128			127,273			116,864
Total operating expenses	870,813		798,229			1,116,171			1,061,883			2,974,944			2,815,096
Operating income	67,112		61,985			156,377			146,684			303,168			297,634
Other income	1,017		1,049			1,011			1,741			2,809			3,662
Interest expense	20,303		22,868			20,909			22,278			61,978			67,365
Income before income taxes	47,826		40,166			136,479			126,147			243,999			233,931
Income taxes	12,188		8,301			46,930			37,761			74,406			67,381
Income from continuing operations	35,638		31,865			89,549			88,386			169,593			166,550
Income (loss) from discontinued operations, net of tax (Note 8)	1,687		(18,036		)
Net income	37,325		13,829
Loss from discontinued operations, net of tax (Note 8)						(2,198		)	(5,400		)	(3,702		)	(299,538		)
Net income (loss)						87,351			82,986			165,891			(132,988		)
Loss from discontinued operations attributable to noncontrolling interest (Note 8)	—		(11,040		)	—			—			—			(131,691		)
Loss on redemption of preferred stocks						—			—			600			—
Dividends declared on preferred stocks	171		171			—			171			171			514
Earnings on common stock	$	37,154	$	24,698
Earnings per common share - basic:
Earnings (loss) on common stock						$	87,351		$	82,815		$	165,120		$	(1,811	)
Earnings (loss) per common share - basic:
Earnings before discontinued operations	$	.18	$	.16		$	.46		$	.45		$	.86		$	.85
Discontinued operations attributable to the Company, net of tax	.01		(.03		)	(.01		)	(.03		)	(.01		)	(.86		)
Earnings per common share - basic	$	.19	$	.13
Earnings per common share - diluted:
Earnings (loss) per common share - basic						$	.45		$	.42		$	.85		$	(.01	)
Earnings (loss) per common share - diluted:
Earnings before discontinued operations	$	.18	$	.16		$	.46		$	.45		$	.86		$	.85
Discontinued operations attributable to the Company, net of tax	.01		(.03		)	(.01		)	(.03		)	(.02		)	(.86		)
Earnings per common share - diluted	$	.19	$	.13
Earnings (loss) per common share - diluted						$	.45		$	.42		$	.84		$	(.01	)
Dividends declared per common share	$	.1925	$	.1875		$	.1925		$	.1875		$	.5775		$	.5625
Weighted average common shares outstanding - basic	195,304		195,284			195,304			195,304			195,304			195,298
Weighted average common shares outstanding - diluted	196,023		195,284			195,783			195,811			195,922			195,794

The accompanying notes are an integral part of these consolidated financial statements.

MDU Resources Group, Inc.

Consolidated Statements of Comprehensive Income

(Unaudited)

Three Months Ended
March 31,
2017 2016
(In thousands)
Net income $ 37,325
$ 13,829
Other comprehensive loss:
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $56 and $57 for the three months ended in 2017 and 2016, respectively 91
92
Postretirement liability adjustment:
Amortization of postretirement liability (gains) losses included in net periodic benefit cost, net of tax of $217 and $(969) for the three months ended in 2017 and 2016, respectively 357
(1,595 )
Reclassification of postretirement liability adjustment from regulatory asset, net of tax of $(725) and $0 for the three months ended in 2017 and 2016, respectively (917 ) —
Postretirement liability adjustment (560 ) (1,595 )
Foreign currency translation adjustment recognized during the period, net of tax of $5 and $15 for the three months ended in 2017 and 2016, respectively 9
25
Net unrealized gain on available-for-sale investments:
Net unrealized gain (loss) on available-for-sale investments arising during the period, net of tax of $(15) and $5 for the three months ended in 2017 and 2016, respectively (27 ) 8
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $19 and $19 for the three months ended in 2017 and 2016, respectively 35
36
Net unrealized gain on available-for-sale investments 8
44
Other comprehensive loss (452 ) (1,434 )
Comprehensive income 36,873
12,395
Comprehensive loss from discontinued operations attributable to noncontrolling interest —
(11,040 )
Comprehensive income attributable to common stockholders $ 36,873
$ 23,435



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands)
Net income (loss)	$	87,351		$	82,986		$	165,891		$	(132,988	)
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $56 and $56 for the three months ended and $168 and $170 for the nine months ended in 2017 and 2016, respectively	92			92			275			275
Postretirement liability adjustment:
Amortization of postretirement liability (gains) losses included in net periodic benefit cost (credit), net of tax of $203 and $143 for the three months ended and $609 and $(676) for the nine months ended in 2017 and 2016, respectively	333			236			1,002			(1,111		)
Reclassification of postretirement liability adjustment from regulatory asset, net of tax of $0 and $0 for the three months ended and $(725) and $0 for the nine months ended in 2017 and 2016, respectively	—			—			(917		)	—
Postretirement liability adjustment	333			236			85			(1,111		)
Foreign currency translation adjustment recognized during the period, net of tax of $9 and $(2) for the three months ended and $5 and $32 for the nine months ended in 2017 and 2016, respectively	15			(4		)	9			52
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(10) and $(23) for the three months ended and $(38) and $(35) for the nine months ended in 2017 and 2016, respectively	(19		)	(42		)	(70		)	(65		)
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $14 and $18 for the three months ended and $50 and $57 for the nine months ended in 2017 and 2016, respectively	27			33			93			106
Net unrealized gain (loss) on available-for-sale investments	8			(9		)	23			41
Other comprehensive income (loss)	448			315			392			(743		)
Comprehensive income (loss)	87,799			83,301			166,283			(133,731		)
Comprehensive loss from discontinued operations attributable to noncontrolling interest	—			—			—			(131,691		)
Comprehensive income (loss) attributable to common stockholders	$	87,799		$	83,301		$	166,283		$	(2,040	)

The accompanying notes are an integral part of these consolidated financial statements.

MDU Resources Group, Inc.

Consolidated Balance Sheets

(Unaudited)


	March 31, 2017			March 31, 2016			December 31, 2016			September 30, 2017			September 30, 2016			December 31, 2016
(In thousands, except shares and per share amounts)	(In thousands, except shares and per share amounts)									(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	50,735		$	90,573		$	46,107		$	37,356		$	59,868		$	46,107
Receivables, net	554,185			526,619			630,243			739,402			665,142			630,243
Inventories	250,609			259,756			238,273			232,555			245,790			238,273
Prepayments and other current assets	79,254			52,380			48,461			89,625			49,082			48,461
Current assets held for sale	7,290			99,544			14,391			304			45,867			14,391
Total current assets	942,073			1,028,872			977,475			1,099,242			1,065,749			977,475
Investments	129,009			121,955			125,866			133,895			126,048			125,866
Property, plant and equipment	6,544,077			6,448,514			6,510,229			6,658,891			6,588,445			6,510,229
Less accumulated depreciation, depletion and amortization	2,609,303			2,521,108			2,578,902			2,667,762			2,583,566			2,578,902
Net property, plant and equipment	3,934,774			3,927,406			3,931,327			3,991,129			4,004,879			3,931,327
Deferred charges and other assets:
Goodwill	631,791			641,527			631,791			631,791			641,527			631,791
Other intangible assets, net	5,347			7,803			5,925			4,209			6,529			5,925
Other	409,745			351,814			415,419			419,846			360,537			415,419
Noncurrent assets held for sale	95,719			485,885			196,664			64,333			112,440			196,664
Total deferred charges and other assets	1,142,602			1,487,029			1,249,799			1,120,179			1,121,033			1,249,799
Total assets	$	6,148,458		$	6,565,262		$	6,284,467		$	6,344,445		$	6,317,709		$	6,284,467
Liabilities and Equity
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year	$	43,499		$	98,540		$	43,598		$	148,499		$	93,598		$	43,598
Accounts payable	239,013			233,021			279,962			304,101			281,373			279,962
Taxes payable	74,638			56,298			48,164			108,946			59,747			48,164
Dividends payable	37,767			36,791			37,767			37,596			36,791			37,767
Accrued compensation	32,350			40,420			65,867			67,097			58,604			65,867
Other accrued liabilities	188,373			182,804			184,377			184,580			191,904			184,377
Current liabilities held for sale	2,394			117,777			9,924			5,749			18,065			9,924
Total current liabilities	618,034			765,651			669,659			856,568			740,082			669,659
Long-term debt	1,659,507			1,759,514			1,746,561			1,592,053			1,808,350			1,746,561
Deferred credits and other liabilities:
Deferred income taxes	666,905			670,299			668,226			652,413			662,326			668,226
Other	890,107			811,789			883,777			889,494			821,890			883,777
Noncurrent liabilities held for sale	—			62,625			—
Total deferred credits and other liabilities	1,557,012			1,544,713			1,552,003			1,541,907			1,484,216			1,552,003
Commitments and contingencies
Equity:
Stockholders' equity:
Preferred stocks	15,000			15,000			15,000			—			15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value Shares issued - 195,843,297 at March 31, 2017 and 2016 and December 31, 2016	195,843			195,843			195,843
Authorized - 500,000,000 shares, $1.00 par value Shares issued - 195,843,297 at September 30, 2017 and 2016 and December 31, 2016										195,843			195,843			195,843
Other paid-in capital	1,231,171			1,229,431			1,232,478			1,232,766			1,231,396			1,232,478
Retained earnings	911,702			984,315			912,282			964,275			884,339			912,282
Accumulated other comprehensive loss	(36,185		)	(38,582		)	(35,733		)	(35,341		)	(37,891		)	(35,733		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,298,905			2,367,381			2,301,244			2,353,917			2,270,061			2,301,244
Total stockholders' equity	2,313,905			2,382,381			2,316,244			2,353,917			2,285,061			2,316,244
Noncontrolling interest	—			113,003			—
Total equity	2,313,905			2,495,384			2,316,244
Total liabilities and equity	$	6,148,458		$	6,565,262		$	6,284,467
Total liabilities and stockholders' equity										$	6,344,445		$	6,317,709		$	6,284,467

The accompanying notes are an integral part of these consolidated financial statements.

MDU Resources Group, Inc.

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended						Nine Months Ended
	March 31,						September 30,
	2017			2016			2017			2016
	(In thousands)						(In thousands)
Operating activities:
Net income	$	37,325		$	13,829
Income (loss) from discontinued operations, net of tax	1,687			(18,036		)
Net income (loss)							$	165,891		$	(132,988	)
Loss from discontinued operations, net of tax							(3,702		)	(299,538		)
Income from continuing operations	35,638			31,865			169,593			166,550
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	51,325			54,884			155,138			163,226
Deferred income taxes	(332		)	7,926			(16,777		)	(1,346		)
Changes in current assets and liabilities, net of acquisitions:
Receivables	63,684			61,931			(121,128		)	(75,308		)
Inventories	(13,676		)	(18,828		)	2,047			(4,153		)
Other current assets	(31,006		)	(22,909		)	(40,655		)	(18,824		)
Accounts payable	(23,380		)	(40,584		)	30,097			15,514
Other current liabilities	(1,179		)	18,690			66,647			48,973
Other noncurrent changes	2,161			(7,711		)	(15,081		)	(25,284		)
Net cash provided by continuing operations	83,235			85,264			229,881			269,348
Net cash provided by (used in) discontinued operations	3,304			(39,715		)
Net cash provided by discontinued operations							42,020			7,127
Net cash provided by operating activities	86,539			45,549			271,901			276,475
Investing activities:
Capital expenditures	(72,316		)	(114,706		)	(222,084		)	(303,873		)
Net proceeds from sale or disposition of property and other	117,967			10,411			121,162			17,583
Investments	(116		)	(503		)	(260		)	56
Net cash provided by (used in) continuing operations	45,535			(104,798		)
Net cash used in continuing operations							(101,182		)	(286,234		)
Net cash provided by discontinued operations	54			25,263			2,234			31,918
Net cash provided by (used in) investing activities	45,589			(79,535		)
Net cash used in investing activities							(98,948		)	(254,316		)
Financing activities:
Issuance of long-term debt	59,985			226,585			133,437			341,777
Repayment of long-term debt	(147,277		)	(164,855		)	(183,968		)	(236,433		)
Dividends paid	(37,767		)	(36,784		)	(113,131		)	(110,366		)
Redemption of preferred stock							(15,600		)	—
Repurchase of common stock	(1,684		)	—			(1,684		)	—
Tax withholding on stock-based compensation	(757		)	(316		)	(757		)	(323		)
Net cash provided by (used in) continuing operations	(127,500		)	24,630
Net cash provided by discontinued operations	—			16,025
Net cash provided by (used in) financing activities	(127,500		)	40,655
Net cash used in continuing operations							(181,703		)	(5,345		)
Net cash used in discontinued operations							—			(40,852		)
Net cash used in financing activities							(181,703		)	(46,197		)
Effect of exchange rate changes on cash and cash equivalents	—			1			(1		)	3
Increase in cash and cash equivalents	4,628			6,670
Decrease in cash and cash equivalents							(8,751		)	(24,035		)
Cash and cash equivalents -- beginning of year	46,107			83,903			46,107			83,903
Cash and cash equivalents -- end of period	$	50,735		$	90,573		$	37,356		$	59,868

The accompanying notes are an integral part of these consolidated financial statements.

MDU Resources Group, Inc.

Notes to Consolidated

Financial Statements

~~March 31,~~September 30, 2017 and 2016

(Unaudited)

Note 1 - Basis of presentation

The accompanying consolidated interim financial statements were prepared in ~~conformity~~accordance with GAAP for interim financial information and with the ~~basis~~instructions to Form 10-Q and Rule 10-01 of presentation reflected in the consolidated financial statements included in the Company's 2016 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB.Regulation S-X. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2016 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after ~~March 31,~~September 30, 2017, up to the date of issuance of these consolidated interim financial statements.

The assets and liabilities for the Company's discontinued operations have been classified as held for sale and the results of operations are shown in ~~income (loss)~~loss from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. ~~The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated.~~ At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations. For more information on the Company's discontinued operations, see Note 8.

Note 2 - Seasonality of operations

Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.

Note 3 - Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was ~~$26.3~~$27.2 million, ~~$30.5~~$26.3 million and $29.2 million at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, was ~~$10.9~~$9.0 million, ~~$11.1~~$10.2 million and $10.5 million, respectively.

Note 4 - Inventories and natural gas in storage

Natural gas in storage for the Company's regulated operations is generally carried at lower of cost or net realizable value, or cost using the last-in, first-out method. All other inventories are stated at the lower of cost or net realizable value. The portion of the cost of natural gas in storage expected to be used within one year is included in inventories. Inventories consisted of:



	September 30, 2017		September 30, 2016		December 31, 2016
	(In thousands)
Aggregates held for resale	$	116,399	$	119,078	$	115,471
Natural gas in storage (current)	29,974		35,625		25,761
Asphalt oil	26,682		23,480		29,103
Materials and supplies	20,778		18,584		18,372
Merchandise for resale	15,346		15,672		16,437
Other	23,376		33,351		33,129
Total	$	232,555	$	245,790	$	238,273

March 31, 2017
March 31, 2016
December 31, 2016
(In thousands)
Aggregates held for resale $ 120,392
$ 127,101
$ 115,471
Asphalt oil 50,538
52,065
29,103
Materials and supplies 22,074
21,645
18,372
Merchandise for resale 16,546
17,441
16,437
Natural gas in storage (current) 11,282
11,305
25,761
Other 29,777
30,199
33,129
Total $ 250,609
$ 259,756
$ 238,273

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in deferred charges and other assets - other and was $49.5 million, $49.1 million and $49.5 million at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, respectively.

Note 5 - Earnings (loss) per common share

Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of outstanding performance share awards. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculations was as follows:



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(In thousands)
Weighted average common shares outstanding - basic	195,304	195,304	195,304	195,298
Effect of dilutive performance share awards	479	507	618	496
Weighted average common shares outstanding - diluted	195,783	195,811	195,922	195,794
Shares excluded from the calculation of diluted earnings per share	—	—	—	—

Three Months Ended
March 31,
2017
2016
(In thousands)
Weighted average common shares outstanding - basic 195,304
195,284
Effect of dilutive performance share awards 719
—
Weighted average common shares outstanding - diluted 196,023
195,284
Shares excluded from the calculation of diluted earnings per share —
—

Note 6 - New accounting standards

~~Revenue from Contracts with Customers~~Recently adopted accounting standards

Balance Sheet Classification of Deferred Taxes In May 2014, the FASB issued guidance on accounting for revenue from contracts with customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry specific guidance. This guidance was to be effective for the Company on January 1, 2017. In AugustNovember 2015, the FASB issued guidance ~~deferring~~regarding the ~~effective date~~classification of deferred taxes on the ~~revenue~~balance sheet. The guidance ~~one year~~requires all deferred tax assets and ~~allowing entities~~liabilities to ~~early adopt. With this decision,~~be classified as noncurrent. These amendments align GAAP with IFRS. The Company adopted the guidance will be effective for the Company on January 1, 2018. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the ~~period~~fourth quarter of 2016 and applied the retrospective method of adoption. ~~In addition, the modified approach will require additional disclosures. The Company is planning to adopt the guidance using the modified retrospective approach.~~ The guidance ~~will require expanded disclosures, both quantitative and qualitative, related~~required a reclassification of current deferred income taxes to noncurrent deferred income taxes on the ~~nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The Company continues to evaluate~~Consolidated Balance Sheets, but did not impact the ~~effects the guidance will have on its~~Company's results of operations ~~financial position~~or cash flows. As a result of the retrospective application of this change in accounting principle, the Company reclassified deferred income taxes of $31.4 million from current assets - deferred income taxes to deferred credits and ~~cash flows.~~other liabilities - deferred income taxes on its Consolidated Balance Sheet at September 30, 2016.

Simplifying the Measurement of Inventory In July 2015, the FASB issued guidance regarding inventory that is measured using the first-in, first-out or average cost method. The guidance does not apply to inventory measured using the last-in, first-out or the retail inventory method. The guidance requires inventory within its scope to be measured at the lower of cost or net realizable value, which is the estimated selling price in the normal course of business less reasonably predictable costs of completion, disposal and transportation. These amendments more closely align GAAP with IFRS. The Company ~~implemented~~adopted the guidance on January 1, 2017, on a prospective basis. The guidance did not have a material effect on the Company's results of operations, financial position, cash flows or disclosures.

Improvements to Employee Share-Based Payment Accounting In March 2016, the FASB issued guidance regarding simplification of several aspects of the accounting for share-based payment transactions. The guidance affects the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows and calculation of dilutive shares. The Company adopted the guidance on January 1, 2017. All amendments in the guidance that apply to the Company were adopted on a prospective basis resulting in no adjustments being made to retained earnings. The adoption of the guidance impacted the Consolidated Statement of Income and the Consolidated Balance Sheet ~~Classification~~in the first quarter of ~~Deferred Taxes~~ 2017 due to the taxes related to the stock-based compensation award that vested in February 2017 being recognized as income tax expense as compared to a reduction to additional paid-in capital under the previous guidance. Adoption of the guidance also increased the number of shares included in the diluted earnings per share calculation due to the exclusion of tax benefits in the incremental shares calculation. The change in the weighted average common shares outstanding - diluted did not result in a material effect on the earnings per common share - diluted.

Recently issued accounting standards not yet adopted

Revenue from Contracts with CustomersIn ~~November~~May 2014, the FASB issued guidance on accounting for revenue from contracts with customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry specific guidance. In August 2015, the FASB issued guidance ~~regarding~~deferring the ~~classification~~effective date of ~~deferred taxes~~the revenue guidance and allowing entities to early adopt. With this decision, the guidance will be effective for the Company on January 1, 2018. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance.

The Company plans to adopt the guidance on January 1, 2018, and to use the modified retrospective approach. Under the modified retrospective approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. To date, the Company has not identified any material cumulative effect adjustments to be made to retained earnings. In addition, the guidance will require expanded disclosures, both quantitative and qualitative, related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. To date, the Company has reviewed nearly all of its revenue streams, completing the

preliminary evaluation of the impact of this guidance. Based on the ~~balance sheet. The guidance requires all deferred tax assets and liabilities to be classified as noncurrent. These amendments will align GAAP with IFRS. Entities had~~preliminary evaluation, the ~~option to apply the guidance prospectively, for all deferred tax assets and liabilities, or retrospectively. The~~ Company ~~adopted the guidance~~does not anticipate a significant change in the ~~fourth quarter~~timing of 2016 and applied the retrospective method of adoption. The guidance required a reclassification of current deferred income taxes to noncurrent deferred income taxes on the Consolidated Balance Sheets, but did not impact the Company'srevenue recognition, results of operations, financial position or cash ~~flows. As a result of~~flows, however the ~~retrospective application~~Company will continue to evaluate the impact of this ~~change in accounting principle,~~guidance through the ~~Company reclassified deferred income taxes~~date of ~~$34.2 million from current assets - deferred income taxes to deferred credits and other liabilities - deferred income taxes on its Consolidated Balance Sheet at March 31, 2016.~~adoption.

Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued guidance regarding the classification and measurement of financial instruments. The guidance revises the way an entity classifies and measures investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and amends certain disclosure requirements related to the fair value of financial instruments. This guidance will be effective for the Company on January 1, 2018, with early adoption of certain amendments permitted. The guidance should be applied using a modified retrospective approach with the exception of equity securities without readily determinable fair values which will be applied prospectively. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

~~Leases~~ In February 2016, the FASB issued guidance regarding leases. The guidance requires lessees to recognize a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the statement of financial position for leases with terms of more than 12 months. The guidance also requires additional disclosures, both quantitative and qualitative, related to operating and finance leases for the lessee and sales-type, direct financing and operating

leases for the lessor. This guidance will be effective for the Company on January 1, 2019, and should be applied using a modified retrospective approach with early adoption permitted. There are a number of industry-specific implementation issues that are still unresolved and the final resolution of these issues could significantly impact the number of contracts that would be considered a lease for the Company under the new guidance. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

~~Improvements to Employee Share-Based Payment Accounting~~ In March 2016, the FASB issued guidance regarding simplification of several aspects of the accounting for share-based payment transactions. The guidance affects the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows and calculation of dilutive shares. Certain amendments of this guidance were to be applied retrospectively and others prospectively. The Company adopted the guidance on January 1, 2017. All amendments in the guidance that apply to the Company were adopted on a prospective basis resulting in no adjustments being made to retained earnings. The adoption of the guidance impacted the Consolidated Statements of Income and the Consolidated Balance Sheets due to the taxes related to the stock-based compensation award that vested in February 2017 being recognized as income tax expense as compared to a reduction to additional paid-in capital under the previous guidance. Adoption of the guidance also increased the number of shares included in the diluted earnings per share calculation due to the exclusion of tax benefits in the incremental shares calculation. The change in the weighted average common shares outstanding - diluted did not result in a material effect on the earnings per common share - diluted.

Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued guidance to clarify the classification of certain cash receipts and payments in the statement of cash flows. The guidance is intended to standardize the presentation and classification of certain transactions, including cash payments for debt prepayment or extinguishment, proceeds from insurance claim settlements and distributions from equity method investments. In addition, the guidance clarifies how to classify transactions that have characteristics of more than one class of cash flows. This guidance will be effective for the Company on January 1, 2018, with early adoption permitted. ~~An entity that elects early adoption must adopt all the amendments in the same period and apply any adjustments as of the beginning of the fiscal year.~~ Entities must apply the guidance retrospectively unless it is impracticable to do so, in which case they may apply it prospectively as of the earliest date practicable. The Company ~~is evaluating~~plans to adopt the ~~effects the adoption~~guidance on January 1, 2018. The Company's initial evaluation of the ~~new~~ guidance did not identify any changes to the current presentation of the statement of cash flows; therefore, no retrospective adjustments to prior periods will ~~have on its cash flows and disclosures.~~be necessary.

Clarifying the Definition of a Business In January 2017, the FASB issued guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The guidance will also affect other aspects of accounting, such as determining reporting units for goodwill testing and whether an entity has acquired or sold a business. The guidance will be effective for the Company on January 1, 2018, and should be applied on a prospective basis with early adoption permitted for transactions that occur before the issuance or effective date of the amendments and only when the transactions have not been reported in the financial statements or made available for issuance. The Company ~~is evaluating~~expects to adopt this guidance as required and does not expect the ~~effects the adoption of the new~~ guidance ~~will~~to have a material effect on its results of operations, financial position, cash flows and disclosures.

~~Simplifying the Test for Goodwill Impairment~~ In January 2017, the FASB issued guidance on simplifying the test for goodwill impairment by eliminating Step 2, which required an entity to measure the amount of impairment loss by comparing the implied fair value of reporting unit goodwill with the carrying amount of such goodwill. This guidance requires entities to perform a quantitative impairment test, previously Step 1, to identify both the existence of impairment and the amount of impairment loss by comparing the fair value of a reporting unit to its carrying amount. Entities will continue to have the option of performing a qualitative assessment to determine if the quantitative impairment test is necessary. The guidance also requires additional disclosures if an entity has one or more reporting units with zero or negative carrying amounts of net assets. The guidance will be effective for the Company on January 1, 2020, and should be applied on a prospective basis with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued guidance to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. The guidance requires the service cost component to be presented in the income statement in the same line item or items as other compensation costs arising from services performed during the period. Other components of net benefit cost shall be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The guidance also only allows the service cost component to be capitalized. The guidance will be effective for the Company on January 1, 2018, including interim periods, with early adoption permitted as of the beginning of an annual period for which the financial statements have not been issued. The guidance shall be applied on a retrospective basis for the financial statement presentation and on a prospective basis for the capitalization of the service cost component.

The Company plans to adopt the guidance as required on January 1, 2018, which will include the reclassification of all components of net periodic benefit costs, except for the service cost component, from operating expenses to other income on the Consolidated Statements of Income. The impact upon adoption of the new guidance will be an increase to operating income and decrease to other income on the Consolidated Statements of Income and no impact to earnings. The guidance will not have a material impact on the Company's disclosures or cash flows.

Leases In February 2016, the FASB issued guidance regarding leases. The guidance requires lessees to recognize a lease liability and a right-of-use asset on the balance sheet for operating and financing leases with terms of more than 12 months. The guidance remains largely the same for lessors, although some changes were made to better align lessor accounting with the new lessee accounting and to align with the revenue recognition standard. The guidance also requires additional disclosures, both quantitative and qualitative, related to operating and finance leases for the lessee and sales-type, direct financing and operating leases for the lessor. This guidance will be effective for the Company on January 1, 2019, and should be applied using a modified retrospective approach with early adoption permitted. The Company continues to evaluate the potential impact the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures. The Company is planning to adopt the standard on January 1, 2019, utilizing the practical expedient that allows the Company to not reassess whether an expired or existing contract contains a lease, the classification of leases or initial direct costs.

Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued guidance on simplifying the test for goodwill impairment by eliminating Step 2, which required an entity to measure the amount of impairment loss by comparing the implied fair value of reporting unit goodwill with the carrying amount of such goodwill. This guidance requires entities to perform a quantitative impairment test, previously Step 1, to identify both the existence of impairment and the amount of impairment loss

by comparing the fair value of a reporting unit to its carrying amount. Entities will continue to have the option of performing a qualitative assessment to determine if the quantitative impairment test is necessary. The guidance also requires additional disclosures if an entity has one or more reporting units with zero or negative carrying amounts of net assets. The guidance will be effective for the Company on January 1, 2020, and should be applied on a prospective basis with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

Note 7 - Comprehensive income (loss)

The after-tax changes in the components of accumulated other comprehensive loss were as follows:


Three Months Ended March 31, 2017	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
Three Months Ended September 30, 2017																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	(2,300	)	$	(33,221	)	$	(149	)	$	(63	)	$	(35,733	)	$	(2,117	)	$	(33,469	)	$	(155	)	$	(48	)	$	(35,789	)
Other comprehensive income (loss) before reclassifications	—			—			9			(27		)	(18		)	—			—			15			(19		)	(4		)
Amounts reclassified from accumulated other comprehensive loss	91			357			—			35			483			92			333			—			27			452
Amounts reclassified to accumulated other comprehensive loss from a regulatory asset	—			(917		)	—			—			(917		)
Net current-period other comprehensive income (loss)	91			(560		)	9			8			(452		)
Net current-period other comprehensive income																92			333			15			8			448
Balance at end of period	$	(2,209	)	$	(33,781	)	$	(140	)	$	(55	)	$	(36,185	)	$	(2,025	)	$	(33,136	)	$	(140	)	$	(40	)	$	(35,341	)


Three Months Ended March 31, 2016	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
Three Months Ended September 30, 2016																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	(2,667	)	$	(34,257	)	$	(200	)	$	(24	)	$	(37,148	)	$	(2,484	)	$	(35,604	)	$	(144	)	$	26		$	(38,206	)
Other comprehensive income before reclassifications	—			—			25			8			33
Other comprehensive loss before reclassifications																—			—			(4		)	(42		)	(46		)
Amounts reclassified from accumulated other comprehensive loss	92			(1,595		)	—			36			(1,467		)	92			236			—			33			361
Net current-period other comprehensive income (loss)	92			(1,595		)	25			44			(1,434		)	92			236			(4		)	(9		)	315
Balance at end of period	$	(2,575	)	$	(35,852	)	$	(175	)	$	20		$	(38,582	)	$	(2,392	)	$	(35,368	)	$	(148	)	$	17		$	(37,891	)



Nine Months Ended September 30, 2017	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,300	)	$	(33,221	)	$	(149	)	$	(63	)	$	(35,733	)
Other comprehensive income (loss) before reclassifications	—			—			9			(70		)	(61		)
Amounts reclassified from accumulated other comprehensive loss	275			1,002			—			93			1,370
Amounts reclassified to accumulated other comprehensive loss from a regulatory asset	—			(917		)	—			—			(917		)
Net current-period other comprehensive income	275			85			9			23			392
Balance at end of period	$	(2,025	)	$	(33,136	)	$	(140	)	$	(40	)	$	(35,341	)



Nine Months Ended September 30, 2016	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,667	)	$	(34,257	)	$	(200	)	$	(24	)	$	(37,148	)
Other comprehensive income (loss) before reclassifications	—			—			52			(65		)	(13		)
Amounts reclassified from accumulated other comprehensive loss	275			(1,111		)	—			106			(730		)
Net current-period other comprehensive income (loss)	275			(1,111		)	52			41			(743		)
Balance at end of period	$	(2,392	)	$	(35,368	)	$	(148	)	$	17		$	(37,891	)

Reclassifications out of accumulated other comprehensive loss were as follows:

Three Months Ended
Location on Consolidated Statements of
Income
March 31,
2017 2016
(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income $ (147 ) $ (149 ) Interest expense
56
57
Income taxes
(91 ) (92 )
Amortization of postretirement liability gains (losses) included in net periodic benefit cost (574 ) 2,564
(a)
217
(969 ) Income taxes
(357 ) 1,595

Reclassification adjustment for loss on available-for-sale investments included in net income (54 ) (55 ) Other income
19
19
Income taxes
(35 ) (36 )
Total reclassifications $ (483 ) $ 1,467



	Three Months Ended						Nine Months Ended						Location on Consolidated Statements of Income
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income (loss)	$	(148	)	$	(148	)	$	(443	)	$	(445	)	Interest expense
	56			56			168			170			Income taxes
	(92		)	(92		)	(275		)	(275		)
Amortization of postretirement liability gains (losses) included in net periodic benefit cost (credit)	(536		)	(379		)	(1,611		)	1,787			(a)
	203			143			609			(676		)	Income taxes
	(333		)	(236		)	(1,002		)	1,111
Reclassification adjustment for loss on available-for-sale investments included in net income (loss)	(41		)	(51		)	(143		)	(163		)	Other income
	14			18			50			57			Income taxes
	(27		)	(33		)	(93		)	(106		)
Total reclassifications	$	(452	)	$	(361	)	$	(1,370	)	$	730

(a) Included in net periodic benefit ~~cost.~~cost (credit). For more information, see Note 14.

Note 8 - Assets held for sale and discontinued operations

Assets held for sale

The assets and liabilities of Pronghorn were classified as held for sale in the fourth quarter of 2016. Pronghorn's results of operations for 2016 were included in the pipeline and midstream segment.

PronghornOn November 21, 2016, WBI Energy Midstream announced it had entered into a purchase and sale agreement to sell its 50 percent non-operating ownership interest in Pronghorn to Tesoro Logistics. The transaction closed on January 1, 2017, which generated approximately $100 million of proceeds for the Company. The sale of Pronghorn further reduces the Company's risk exposure to commodity prices.

The carrying amounts of the major classes of assets and liabilities that were classified as held for sale associated with Pronghorn on the Company's Consolidated Balance Sheets were as follows:



	December 31, 2016
	(In thousands)
Assets
Current assets:
Prepayments and other current assets	$	68
Total current assets held for sale	68
Noncurrent assets:
Net property, plant and equipment	93,424
Goodwill	9,737
Less allowance for impairment of assets held for sale	2,311
Total noncurrent assets held for sale	100,850
Total assets held for sale	$	100,918

December 31, 2016
(In thousands)
Assets
Current assets:
Prepayments and other current assets $ 68
Total current assets held for sale 68
Noncurrent assets:
Net property, plant and equipment 93,424
Goodwill 9,737
Less allowance for impairment of assets held for sale 2,311
Total noncurrent assets held for sale 100,850
Total assets held for sale $ 100,918

Discontinued operations

The assets and liabilities of the Company's discontinued operations have been classified as held for sale and the results of operations are shown in ~~income (loss)~~loss from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. ~~The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated.~~ At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded.

Dakota Prairie RefiningOn June 24, 2016, WBI Energy entered into a membership interest purchase agreement with Tesoro to sell all of the outstanding membership interests in Dakota Prairie Refining to Tesoro. WBI Energy and Calumet each previously owned 50 percent of the Dakota Prairie Refining membership interests and were equal members in building and operating Dakota Prairie Refinery. To effectuate the sale, WBI Energy acquired Calumet’s 50 percent membership interest in Dakota Prairie Refining on June 27, 2016. The sale of the membership interests to Tesoro closed on June 27, 2016. The sale of Dakota Prairie Refining reduces the Company’s risk by decreasing exposure to commodity prices.

In connection with the sale, WBI Energy had cash in an escrow account for RINs obligations, which was included in current assets held for sale on the Consolidated Balance Sheet at September 30, 2016. The Company retained certain liabilities of Dakota Prairie Refining which were reflected in current liabilities held for sale on the Consolidated Balance Sheets. In October 2016, the RINs liability was paid and the cash was removed from escrow. Also, Centennial continues to guarantee certain debt obligations of Dakota Prairie Refining; however, Tesoro has agreed to indemnify Centennial for any losses and litigation expenses arising from the guarantee. For more information related to the guarantee, see Note 16.

The carrying amounts of the major classes of assets and liabilities that are classified as held for sale related to the operations of and activity associated with Dakota Prairie Refining on the Company's Consolidated Balance Sheets were as follows:



	September 30, 2017			September 30, 2016		December 31, 2016
	(In thousands)
Assets
Current assets:
Receivables, net	$	—		$	13	$	—
Income taxes receivable	8,444		(a)	32,388		13,987
Prepayments and other current assets	—			7,741		—
Total current assets held for sale	8,444			40,142		13,987
Noncurrent assets:
Deferred income taxes	—			2,984		—
Total noncurrent assets held for sale	—			2,984		—
Total assets held for sale	$	8,444		$	43,126	$	13,987
Liabilities
Current liabilities:
Accounts payable	$	—		$	7,063	$	7,425
Other accrued liabilities	—			7,743		—
Total current liabilities held for sale	—			14,806		7,425
Noncurrent liabilities:
Deferred income taxes (b)	55			—		14
Total noncurrent liabilities held for sale	55			—		14
Total liabilities held for sale	$	55		$	14,806	$	7,439

March 31, 2017
March 31, 2016
December 31, 2016
(In thousands)
Assets
Current assets:
Cash and cash equivalents $ —
$ 365
$ —
Receivables, net —
11,169
—
Inventories —
17,056
—
Income taxes receivable 11,756
7,077
13,987
Prepayments and other current assets —
6,124
—
Total current assets held for sale 11,756
41,791
13,987
Noncurrent assets:
Net property, plant and equipment —
407,247
—
Other —
8,846
—
Total noncurrent assets held for sale —
416,093
—
Total assets held for sale $ 11,756
$ 457,884
$ 13,987
Liabilities
Current liabilities:
Short-term borrowings $ —
$ 61,525
$ —
Long-term debt due within one year —
6,375
—
Accounts payable 16
27,454
7,425
Taxes payable —
1,001
—
Accrued compensation —
717
—
Other accrued liabilities —
7,155
—
Total current liabilities held for sale 16
104,227
7,425
Noncurrent liabilities:
Long-term debt —
62,625
—
Deferred income taxes (a) 55
24,137
14
Total noncurrent liabilities held for sale 55
86,762
14
Total liabilities held for sale $ 71
$ 190,989
$ 7,439


(a)	On the Company's Consolidated Balance Sheets, this amount was reclassified to income taxes payable and is reflected in current liabilities held for sale.


(b)	On the Company's Consolidated Balance Sheets, these amounts were reclassified to noncurrent deferred income tax assets and are

reflected in noncurrent assets held for sale.

In the first quarter of 2017, the Company recorded a reversal of a previously accrued liability of $7.0 million ($4.3 million after tax) due to the resolution of a legal matter. At ~~March 31,~~September 30, 2017, Dakota Prairie Refining had not incurred any material exit and disposal costs, and does not expect to incur any material exit and disposal costs.

The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the second quarter of 2016, the fair value assessment was determined using the market approach based on the sale transaction to Tesoro. The fair value assessment indicated an impairment based on the carrying value exceeding the fair value, which resulted in the Company recording an impairment of $251.9 million ($156.7 million after tax) in the quarter ended June 30, 2016. The impairment was included in operating expenses from discontinued operations. The fair value of Dakota Prairie Refining’s assets has been categorized as Level 3 in the fair value hierarchy.

FidelityIn the second quarter of 2015, the Company began the marketing and sale process of Fidelity with an anticipated sale to occur within one year. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell all of Fidelity's oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. The sale of Fidelity was part of the Company's strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value.

The carrying amounts of the major classes of assets and liabilities that are classified as held for sale related to the operations of Fidelity on the Company's Consolidated Balance Sheets were as follows:



	September 30, 2017		September 30, 2016			December 31, 2016
	(In thousands)
Assets
Current assets:
Receivables, net	$	304	$	7,930		$	355
Total current assets held for sale	304		7,930			355
Noncurrent assets:
Net property, plant and equipment	2,064		5,507			5,507
Deferred income taxes	62,163		104,726			91,098
Other	161		161			161
Less allowance for impairment of assets held for sale	—		938			938
Total noncurrent assets held for sale	64,388		109,456			95,828
Total assets held for sale	$	64,692	$	117,386		$	96,183
Liabilities
Current liabilities:
Accounts payable	$	68	$	175		$	141
Taxes payable	11,745		2,205		(a)	19		(a)
Other accrued liabilities	2,380		3,084			2,358
Total current liabilities held for sale	14,193		5,464			2,518
Total liabilities held for sale	$	14,193	$	5,464		$	2,518

March 31, 2017
March 31, 2016
December 31, 2016

(In thousands)
Assets
Current assets:
Receivables, net $ 266
$ 3,619
$ 355

Inventories —
1,308
—

Income taxes receivable —
50,478
—

Prepayments and other current assets —
2,348
—

Total current assets held for sale 266
57,753
355

Noncurrent assets:
Investments —
37
—

Net property, plant and equipment 4,515
9,363
5,507

Deferred income taxes 91,098
82,994
91,098

Other 161
161
161

Less allowance for impairment of assets held for sale —
(1,374 ) 938

Total noncurrent assets held for sale 95,774
93,929
95,828

Total assets held for sale $ 96,040
$ 151,682
$ 96,183

Liabilities
Current liabilities:
Accounts payable $ 67
$ 7,963
$ 141

Taxes payable 4,732
(a) 35
19
(a)
Accrued compensation —
761
—

Other accrued liabilities 2,311
4,791
2,358

Total current liabilities held for sale 7,110
13,550
2,518

Total liabilities held for sale $ 7,110
$ 13,550
$ 2,518


(a)	On the Company's Consolidated Balance Sheets, these amounts were reclassified to prepayments and other current assets and are reflected in current assets held for sale.

~~in current assets held for sale.~~

The Company reclassified current income tax assets of $47.5 million and current income tax liabilities of $4.1 million to noncurrent assets - deferred income taxes at September 30, 2016, pursuant to the retrospective application of the adoption of the ASU related to the balance sheet classification of deferred taxes. For more information on this ASU, see Note 6.

The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the second quarter of 2016, the fair value assessment was determined using the income and market approaches. The income approach was determined by using the present value of future estimated cash flows. The market approach was based on market transactions of similar properties. The estimated carrying value exceeded the fair value and the Company recorded an impairment of $900,000 ($600,000 after tax) in the second quarter of 2016. In the first quarter of 2016, the fair value assessment was determined using the market approach largely based on a purchase and sale agreement. The estimated fair value exceeded the carrying value and the Company recorded an impairment reversal of $1.4 million ($900,000 after tax) in the first quarter of 2016. The impairment and impairment reversal ~~was~~were included in operating expenses from discontinued operations. The estimated fair value of Fidelity's assets ~~has~~have been categorized as Level 3 in the fair value hierarchy.

The Company incurred transaction costs of approximately $300,000 in the first quarter of 2016. In addition to the transaction costs, and due in part to the change in plans to sell the assets of Fidelity rather than sell Fidelity as a company, Fidelity incurred and expensed approximately ~~$1.8~~$5.6 million of exit and disposal costs for the ~~three~~nine months ended ~~March 31,~~September 30, 2016, and has incurred $10.5 million of exit and disposal costs to date. Fidelity incurred no exit and disposal costs for the three and nine months ended ~~March 31,~~September 30, 2017, and the Company does not expect to incur any additional material exit and disposal costs. The exit and disposal costs are associated with severance and other related matters and exclude the office lease expiration discussed in the following paragraph.

Fidelity vacated its office space in Denver, Colorado in 2016. The Company incurred lease payments of approximately ~~$500,000~~$900,000 in 2016. A lease termination payment of $3.2 million was made during the second quarter of 2016. Existing office furniture and fixtures were relinquished to the lessor in the ~~first~~second quarter of 2016.

Dakota Prairie Refining and Fidelity The reconciliation of the major classes of income and expense constituting pretax income (loss) from discontinued operations, which includes Dakota Prairie Refining and Fidelity, to the after-tax ~~income (loss)~~loss from discontinued operations on the Company's Consolidated Statements of Income was as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands)
Operating revenues	$	121		$	162		$	356		$	122,894
Operating expenses	384			230			(4,988		)	513,756
Operating income (loss)	(263		)	(68		)	5,344			(390,862		)
Other income (expense)	—			375			(13		)	762
Interest expense	—			—			239			1,753
Income (loss) from discontinued operations before income taxes	(263		)	307			5,092			(391,853		)
Income taxes	1,935			5,707			8,794			(92,315		)
Loss from discontinued operations	(2,198		)	(5,400		)	(3,702		)	(299,538		)
Loss from discontinued operations attributable to noncontrolling interest	—			—			—			(131,691		)
Loss from discontinued operations attributable to the Company	$	(2,198	)	$	(5,400	)	$	(3,702	)	$	(167,847	)

Three Months Ended
March 31,
2017
2016
(In thousands)
Operating revenues $ 105
$ 47,976
Operating expenses (6,577 ) 69,769
Operating income (loss) 6,682
(21,793 )
Other income (expense) (15 ) 204
Interest expense —
922
Income (loss) from discontinued operations before income taxes 6,667
(22,511 )
Income taxes 4,980
(4,475 )
Income (loss) from discontinued operations 1,687
(18,036 )
Loss from discontinued operations attributable to noncontrolling interest —
(11,040 )
Income (loss) from discontinued operations attributable to the Company $ 1,687
$ (6,996 )

The pretax income (loss) from discontinued operations attributable to the Company, related to the operations of and activity associated with Dakota Prairie Refining, ~~was $6.9 million~~were $0 and ~~$(9.9) million~~$935,000 for the three months ended ~~March 31,~~and $6.9 million and $(253.0) million for the nine months ended September 30, 2017 and 2016, respectively.

Note 9 - Goodwill and other intangible assets

The changes in the carrying amount of goodwill were as follows:



Nine Months Ended September 30, 2017	Balance at January 1, 2017		Goodwill Acquired During the Year		Balance at September 30, 2017
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736
Construction materials and contracting	176,290		—		176,290
Construction services	109,765		—		109,765
Total	$	631,791	$	—	$	631,791

Three Months Ended March 31, 2017 Balance at January 1, 2017
Goodwill Acquired
During the Year
Balance at March 31, 2017
(In thousands)
Natural gas distribution $ 345,736
$ —
$ 345,736
Construction materials and contracting 176,290
—
176,290
Construction services 109,765
—
109,765
Total $ 631,791
$ —
$ 631,791


Three Months Ended March 31, 2016	Balance at January 1, 2016		*	Goodwill Acquired During the Year		Balance at March 31, 2016		*
Nine Months Ended September 30, 2016									Balance at January 1, 2016		*	Goodwill Acquired During the Year		Balance at September 30, 2016		*
	(In thousands)								(In thousands)
Natural gas distribution	$	345,736		$	—	$	345,736		$	345,736		$	—	$	345,736
Pipeline and midstream	9,737			—		9,737			9,737			—		9,737
Construction materials and contracting	176,290			—		176,290			176,290			—		176,290
Construction services	103,441			6,323		109,764			103,441			6,323		109,764
Total	$	635,204		$	6,323	$	641,527		$	635,204		$	6,323	$	641,527

* Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods.



Year Ended December 31, 2016	Balance at January 1, 2016		*	Goodwill Acquired During the Year		Held for Sale			Balance at December 31, 2016
	(In thousands)
Natural gas distribution	$	345,736		$	—	$	—		$	345,736
Pipeline and midstream	9,737			—		(9,737		)	—
Construction materials and contracting	176,290			—		—			176,290
Construction services	103,441			6,324		—			109,765
Total	$	635,204		$	6,324	$	(9,737	)	$	631,791

* Balance is presented net of accumulated impairment of $12.3 million at the pipeline and midstream segment, which occurred in prior periods.

Other amortizable intangible assets were as follows:



	September 30, 2017		September 30, 2016		December 31, 2016
	(In thousands)
Customer relationships	$	15,248	$	17,145	$	17,145
Less accumulated amortization	13,176		13,524		13,917
	2,072		3,621		3,228
Noncompete agreements	2,430		2,430		2,430
Less accumulated amortization	1,769		1,622		1,658
	661		808		772
Other	7,020		7,764		7,768
Less accumulated amortization	5,544		5,664		5,843
	1,476		2,100		1,925
Total	$	4,209	$	6,529	$	5,925

March 31, 2017
March 31, 2016
December 31, 2016
(In thousands)
Customer relationships $ 15,745
$ 17,145
$ 17,145
Less accumulated amortization 12,910
12,680
13,917
2,835
4,465
3,228
Noncompete agreements 2,430
2,430
2,430
Less accumulated amortization 1,695
1,548
1,658
735
882
772
Other 7,086
7,764
7,768
Less accumulated amortization 5,309
5,308
5,843
1,777
2,456
1,925
Total $ 5,347
$ 7,803
$ 5,925

Amortization expense for amortizable intangible assets for the three and nine months ended ~~March 31,~~September 30, 2017, was $500,000 and $1.7 million, respectively. Amortization expense for amortizable intangible assets for the three and nine months ended September 30, 2016, was $600,000 and ~~$600,000,~~$1.9 million, respectively. Estimated amortization expense for amortizable intangible assets is $2.2 million in 2017, $1.2 million in 2018, $1.0 million in 2019, $500,000 in 2020, $200,000 in 2021 and $800,000 thereafter.

Note 10 - Fair value measurements

The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled ~~$73.8~~$75.0 million, ~~$69.1~~$72.8 million and $70.9 million, at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were ~~$2.9~~$1.9 million and ~~$1.6~~$6.9 million for the three and nine months ended ~~March 31,~~September 30, 2017, respectively. The net unrealized gains on these investments were $1.4 million and $5.3 million for the three and nine months ended September 30, 2016, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in accumulated other comprehensive income (loss). Details of available-for-sale securities were as follows:


March 31, 2017	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
September 30, 2017										Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	9,971	$	8	$	(94	)	$	9,885	$	9,488	$	11	$	(72	)	$	9,427
U.S. Treasury securities	412		1		—			413		613		—		(1		)	612
Total	$	10,383	$	9	$	(94	)	$	10,298	$	10,101	$	11	$	(73	)	$	10,039



December 31, 2016	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	10,546	$	8	$	(105	)	$	10,449
Total	$	10,546	$	8	$	(105	)	$	10,449

December 31, 2016 Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair Value
(In thousands)
Mortgage-backed securities $ 10,546
$ 8
$ (105 ) $ 10,449
Total $ 10,546
$ 8
$ (105 ) $ 10,449

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.

The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.

The Company's Level 2 money market funds are valued at the net asset value of shares held at the end of the quarter, based on published market quotations on active markets, or using other known sources including pricing from outside sources.

The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

The estimated fair value of the Company's Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the ~~three~~nine months ended ~~March 31,~~September 30, 2017 and 2016, there were no transfers between Levels 1 and 2.

The Company's assets and liabilities measured at fair value on a recurring basis were as follows:

* The insurance contract invests approximately 51 percent in fixed-income investments, 22 percent in common stock of large-cap companies, 13 percent in common stock of mid-cap companies, 11 percent in common stock of small-cap companies, 2 percent in target date investments and 1 percent in cash equivalents.



	Fair Value Measurements at September 30, 2016, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at September 30, 2016
	(In thousands)
Assets:
Money market funds	$	—	$	2,284	$	—	$	2,284
Insurance contract*	—		72,818		—		72,818
Available-for-sale securities:
Mortgage-backed securities	—		9,908		—		9,908
Total assets measured at fair value	$	—	$	85,010	$	—	$	85,010

Fair Value Measurements at March 31, 2016, Using

Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Balance at March 31, 2016
(In thousands)
Assets:
Money market funds $ —
$ 1,442
$ —
$ 1,442
Insurance contract* —
69,110
—
69,110
Available-for-sale securities:
Mortgage-backed securities —
10,499
—
10,499
Total assets measured at fair value $ —
$ 81,051
$ —
$ 81,051

* The insurance contract invests approximately 65 percent in fixed-income investments, 18 percent in common stock of large-cap companies, 9 percent in common stock of mid-cap companies, 6 percent in common stock of small-cap companies, 1 percent in target date investments and 1 percent in cash equivalents.

Fair Value Measurements at December 31, 2016, Using

Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Balance at December 31, 2016
(In thousands)
Assets:
Money market funds $ —
$ 1,602
$ —
$ 1,602
Insurance contract* —
70,921
—
70,921
Available-for-sale securities:
Mortgage-backed securities —
10,449
—
10,449
Total assets measured at fair value $ —
$ 82,972
$ —
$ 82,972

* The insurance contract invests approximately 52 percent in fixed-income investments, 22 percent in common stock of large-cap companies, 13 percent in common stock of mid-cap companies, 10 percent in common stock of small-cap companies, 1 percent in target date investments and 2 percent in cash equivalents.



	Fair Value Measurements at December 31, 2016, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at December 31, 2016
	(In thousands)
Assets:
Money market funds	$	—	$	1,602	$	—	$	1,602
Insurance contract*	—		70,921		—		70,921
Available-for-sale securities:
Mortgage-backed securities	—		10,449		—		10,449
Total assets measured at fair value	$	—	$	82,972	$	—	$	82,972

For information about fair value assessments of assets and liabilities classified as held for sale, see Note 8.

The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt was as follows:



	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at September 30, 2017	$	1,740,552	$	1,846,811
Long-term debt at September 30, 2016	$	1,901,948	$	2,047,339
Long-term debt at December 31, 2016	$	1,790,159	$	1,841,885

Carrying
Amount

Fair
Value

(In thousands)
Long-term debt at March 31, 2017 $ 1,703,006
$ 1,784,588
Long-term debt at March 31, 2016 $ 1,858,054
$ 1,928,150
Long-term debt at December 31, 2016 $ 1,790,159
$ 1,841,885

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

A summary of the changes in equity was as follows:



Nine Months Ended September 30, 2017	Total Equity
	(In thousands)
Balance at December 31, 2016	$	2,316,244
Net income	165,891
Other comprehensive income	392
Dividends declared on preferred stocks	(171		)
Dividends declared on common stock	(112,788		)
Stock-based compensation	2,390
Repurchase of common stock	(1,684		)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	(757		)
Redemption of preferred stock	(15,600		)
Balance at September 30, 2017	$	2,353,917

Effective April 1, 2017, all outstanding preferred stock, including $300,000 of redeemable preferred stock classified as long-term debt, was redeemed for a repurchase price of approximately $15.9 million.

Three Months Ended March 31, 2017
Total
Equity

(In thousands)
Balance at December 31, 2016 $ 2,316,244
Net income 37,325
Other comprehensive loss (452 )
Dividends declared on preferred stocks (171 )
Dividends declared on common stock (37,596 )
Stock-based compensation 996
Repurchase of common stock (1,684 )
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings (757 )
Balance at March 31, 2017 $ 2,313,905



Nine Months Ended September 30, 2016	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2015	$	2,396,505		$	124,043		$	2,520,548
Net loss	(1,297		)	(131,691		)	(132,988		)
Other comprehensive loss	(743		)	—			(743		)
Dividends declared on preferred stocks	(514		)	—			(514		)
Dividends declared on common stock	(109,858		)	—			(109,858		)
Stock-based compensation	2,955			—			2,955
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	(323		)	—			(323		)
Net tax deficit on stock-based compensation	(1,664		)	—			(1,664		)
Contribution from noncontrolling interest	—			7,648			7,648
Balance at September 30, 2016	$	2,285,061		$	—		$	2,285,061

Note 12 - Cash flow information

Cash expenditures for interest and income taxes were as follows:



	Nine Months Ended
	September 30,
	2017		2016
	(In thousands)
Interest, net of amount capitalized and AFUDC - borrowed of $676 and $842 in 2017 and 2016, respectively	$	58,119	$	66,281
Income taxes paid, net*	$	46,430	$	73,771

Noncash investing transactions were as follows:

Note 13 - Business segment data

The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's operations are located within the United States.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.

The pipeline and midstream segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services. For information on the Company's natural gas and oil gathering and processing facility sold on January 1, 2017, see Note 8.

The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.

The construction services segment provides ~~utility~~ construction services specializing in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization. This segment also provides utility excavation and inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and other supplies.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability, automobile liability, pollution liability and other coverages. Centennial Capital also owns certain real and personal property. The Other category also includes certain general and administrative costs (reflected in operation and maintenance expense) and interest expense which were previously allocated to the refining business and Fidelity and do not meet the criteria for income (loss) from discontinued operations. The Other category also includes Centennial Resources' former investment in Brazil.

Discontinued operations includes the results and supporting activities of Dakota Prairie Refining and Fidelity other than certain general and administrative costs and interest expense as described above. Dakota Prairie Refining refined crude oil and produced and sold diesel fuel, naphtha, ATBs and other by-products of the production process. In the second quarter of 2016, the Company sold all of the outstanding membership interests in Dakota Prairie Refining. Fidelity engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell all of Fidelity's oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. For more information on discontinued operations, see Note 8.

The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2016 Annual Report. Information on the Company's businesses was as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands)
External operating revenues:
Regulated operations:
Electric	$	91,531		$	82,156		$	254,330		$	238,911
Natural gas distribution	92,253			87,941			566,364			500,106
Pipeline and midstream	23,152			21,982			45,341			44,980
	206,936			192,079			866,035			783,997
Nonregulated operations:
Pipeline and midstream	5,356			10,732			13,518			29,697
Construction materials and contracting	686,010			724,535			1,388,212			1,475,643
Construction services	374,111			280,801			1,009,693			822,226
Other	135			420			654			1,167
	1,065,612			1,016,488			2,412,077			2,328,733
Total external operating revenues	$	1,272,548		$	1,208,567		$	3,278,112		$	3,112,730

Intersegment operating revenues:
Regulated operations:
Electric	$	—		$	—		$	—		$	—
Natural gas distribution	—			—			—			—
Pipeline and midstream	3,081			3,278			30,923			30,969
	3,081			3,278			30,923			30,969
Nonregulated operations:
Pipeline and midstream	38			41			132			161
Construction materials and contracting	142			155			400			370
Construction services	415			3			715			541
Other	1,910			2,204			5,411			5,542
	2,505			2,403			6,658			6,614
Intersegment eliminations	(5,586		)	(5,681		)	(37,581		)	(37,583		)
Total intersegment operating revenues	$	—		$	—		$	—		$	—

Three Months Ended
March 31,
2017
2016
(In thousands)
External operating revenues:
Regulated operations:
Electric $ 88,225
$ 82,923
Natural gas distribution 342,519
299,395
Pipeline and midstream 2,870
3,547
433,614
385,865
Nonregulated operations:
Pipeline and midstream 3,643
8,697
Construction materials and contracting 200,776
209,852
Construction services 299,572
255,500
Other 320
300
504,311
474,349
Total external operating revenues $ 937,925
$ 860,214

Intersegment operating revenues:

Regulated operations:
Electric $ —
$ —
Natural gas distribution —
—
Pipeline and midstream 21,489
21,098
21,489
21,098
Nonregulated operations:
Pipeline and midstream 34
84
Construction materials and contracting 86
118
Construction services 6
462
Other 1,743
1,669
1,869
2,333
Intersegment eliminations (23,358 ) (23,431 )
Total intersegment operating revenues $ —
$ —



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands)
Earnings (loss) on common stock:
Regulated operations:
Electric	$	15,712		$	12,699		$	37,904		$	31,840
Natural gas distribution	(10,883		)	(12,524		)	14,181			4,940
Pipeline and midstream	5,853			5,389			15,901			16,241
	10,682			5,564			67,986			53,021
Nonregulated operations:
Pipeline and midstream	95			1,304			(770		)	2,043
Construction materials and contracting	63,221			69,523			64,477			88,747
Construction services	13,144			7,234			32,896			20,198
Other	552			(1,009		)	(1,888		)	(3,572		)
	77,012			77,052			94,715			107,416
Intersegment eliminations*	1,855			5,599			6,121			5,599
Earnings on common stock before loss from discontinued operations	89,549			88,215			168,822			166,036
Loss from discontinued operations, net of tax*	(2,198		)	(5,400		)	(3,702		)	(299,538		)
Loss from discontinued operations attributable to noncontrolling interest	—			—			—			(131,691		)
Total earnings (loss) on common stock	$	87,351		$	82,815		$	165,120		$	(1,811	)

Earnings on common stock before income (loss) from

discontinued operations

* Includes ~~an elimination~~eliminations for the presentation of income tax adjustments between continuing and

discontinued operations.

Note 14 - Employee benefit plans

Pension and other postretirement plans

The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost (credit) for the Company's pension and other postretirement benefit plans were as follows:

Postretirement Benefits



	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30,	2017			2016			2017			2016
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	1,130		$	1,236
Interest cost	12,155			12,915			2,449			2,766
Expected return on assets	(15,395		)	(15,693		)	(3,480		)	(3,400		)
Amortization of prior service credit	—			—			(1,029		)	(1,029		)
Amortization of net actuarial loss	4,767			4,660			649			1,118
Net periodic benefit cost (credit), including amount capitalized	1,527			1,882			(281		)	691
Less amount capitalized	245			284			(248		)	4
Net periodic benefit cost (credit)	$	1,282		$	1,598		$	(33	)	$	687

Nonqualified benefit plans

In addition to the qualified plan defined pension benefits reflected in the table, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or, upon death, to their beneficiaries for a 15-year period. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated benefit increases. Vesting for participants not fully vested was retained. The Company's net periodic benefit cost for these plans for the three and nine months ended ~~March 31,~~September 30, 2017, was $1.2 ~~million.~~million and $3.5 million, respectively. The Company's net periodic benefit ~~credit~~cost for these plans for the three and nine months ended ~~March 31,~~September 30, 2016, was$~~1.9~~1.3 million and $600,000, respectively, which reflects a curtailment gain of $3.3 ~~million.~~million in the first quarter of 2016.

Note 15 - Regulatory matters

On September 30, 2015, Great Plains filed an application for a natural gas rate increase with the MNPUC. Great Plains requested a total increase of approximately $1.6 million annually or approximately 6.4 percent above current rates to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes. An interim increase of approximately $1.5 million or approximately 6.4 percent, subject to refund, was effective with service rendered on and after January 1, 2016. The MNPUC issued an order on September 6, 2016, authorizing an increase of approximately $1.1 million annually or approximately 5.2 percent with the requirement that Great Plains submit a compliance filing within 30 days. On September 22, 2016, Great Plains submitted the required compliance filing which included a refund plan to return the amount of interim revenues collected above the final rates. On December 22, 2016, the MNPUC issued an order approving the rates which were effective January 1, 2017. Great Plains issued refunds to customers on February 24, 2017.

On April 29, 2016, Cascade filed an application with the OPUC for a natural gas rate increase of approximately $1.9 million annually or approximately 2.8 percent above current rates. The request includes rate recovery associated with pipeline replacement and improvement projects to ensure the integrity of Cascade's system. On October 6, 2016, Cascade, staff of the OPUC and the interveners in the case filed a stipulation and settlement agreement reflecting an annual increase of approximately $754,000 effective March 1, 2017. The OPUC issued an order approving the stipulation and settlement agreement on December 12, 2016.

On June 10, 2016, Montana-Dakota filed an application for an increase in electric rates with the WYPSC. Montana-Dakota requested an increase of approximately $3.2 million annually or approximately 13.1 percent above current rates to recover Montana-Dakota's increased investment in facilities along with additional depreciation, operation and maintenance expenses including increased fuel costs, and taxes associated with the increases in investment. On December 28, 2016, Montana-Dakota and the interveners of the case filed a stipulation and agreement reflecting an increase of approximately $2.7 million annually or approximately 11.1 percent above current rates. On April 6, 2017, the WYPSC issued a final order approving the stipulation and agreement with rates effective with service rendered on and after March 1, 2017.

On August 12, 2016, Intermountain filed an application with the IPUC for a natural gas rate increase of approximately $10.2 million annually or approximately 4.1 percent above current rates. The request ~~includes~~included rate recovery associated with increased investment in facilities and increased operating expenses. On January 17, 2017, Intermountain provided the IPUC with an updated revenue request of approximately $9.4 million. ~~A hearing was held March 1-3, 2017.~~ On April 28, 2017, the IPUC issued an order approving an increase of approximately $4.1 million or approximately 1.6 percent above current rates based on a 9.5 percent return on equity effective with service rendered on and after May 1, 2017. On May 18, 2017, Intermountain ~~is reviewing~~filed a petition for reconsideration with the ~~final order.~~

IPUC requesting the reconsideration of certain items denied in the order dated April 28, 2017. On June 15, 2017, the IPUC granted the request for reconsideration. On August 17, 2017, Intermountain, the IPUC staff and the interveners of the case filed a stipulation and settlement resolving all issues. The stipulation and settlement reflected an increase of approximately $1.2 million or 1.36 percent more in annual revenue than the amounts approved on April 28, 2017, as well as changes in billing determinants. The total annual increase in revenue of approximately $6.7 million was approved by the IPUC on September ~~1, 2016, and as amended on January 10,~~14, 2017, ~~Montana-Dakota submitted an update to its transmission formula rate under the MISO tariff including a revenue requirement for the Company's multivalue project along~~ with ~~a true-up of prior year expenditures of $11.1 million, which was~~rates effective ~~January~~October 1, 2017.

On December 2, 2016, Montana-Dakota filed an application with the MTPSC requesting authority to implement gas and electric tax tracking adjustments for Montana state and local taxes and fees that reflect the changes in state and local property taxes applicable to natural gas and electric utilities pursuant to Montana law. The requested tax tracking adjustments would result in an increase in revenues of approximately $814,000. On January 17, 2017, the MTPSC issued an order on the tax tracking adjustments. The gas tracking adjustment was approved as an increase to revenues of approximately $474,000 effective January 1, 2017. The electric tax tracking adjustment was approved as an increase to revenues of approximately $251,000 effective May 15, 2017. Montana-Dakota filed a motion for reconsideration of the electric tax tracking adjustment on January 27, 2017. The motion for reconsideration is pending before the MTPSC.

On December 21, 2016, Great Plains filed an application with the MNPUC requesting authority to implement a natural gas utility infrastructure cost tariff of approximately $456,000 ~~annually effective beginning with service rendered May 20, 2017.~~annually. The tariff will allow Great Plains to recover infrastructure investments, not previously included in rates, mandated by federal or state agencies associated with Great Plains' pipeline integrity programs. ~~This matter is pending before~~On October 6, 2017, the ~~MNPUC.~~

~~On April 1, 2017, Montana-Dakota implemented Phase 2~~MNPUC approved the implementation of the ~~electric rate case approved by the MTPSC on March 25, 2016. The~~natural gas utility infrastructure cost tariff to collect an annual increase of ~~$4.7 million is~~approximately $456,000. Great Plains submitted a compliance filing on October 10, 2017, requesting the order to be effective with service rendered on and after ~~April~~November 1, 2017.

On May 31, 2017, Cascade filed an application with the WUTC for an annual pipeline replacement cost recovery mechanism of approximately $1.6 million or approximately .75 percent of additional revenue. The requested increase includes incremental pipeline replacement investments associated with qualifying pipeline integrity projects. On October 12, 2017, Cascade filed a required update revising the request to approximately $1.3 million or approximately .61 percent of additional revenue and on October 26, 2017, the WUTC approved the order with rates effective November 1, 2017.

On June 30, 2017, Montana-Dakota filed an application for advance determination of prudence and a certificate of public convenience and necessity with the NDPSC to purchase an expansion of the Thunder Spirit Wind farm. The advance determination of prudence would provide Montana-Dakota with assurance that the project is prudent and in the best interest of the public and assists in the recovery of Montana-Dakota's investment upon completion of the project. The expansion is expected to serve customers by the end of 2018 and is estimated to cost approximately $85 million. An informal hearing is scheduled for November 3, 2017.

On July 21, 2017, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase of approximately $5.9 million annually or approximately 5.4 percent above current rates. The requested increase is primarily to recover the increased investment in distribution facilities to enhance system safety and reliability and the depreciation and taxes associated

with the increase in investment. Montana-Dakota is also introducing an SSIP and the proposed adjustment mechanism required to fund the SSIP. Montana-Dakota requested an interim increase of approximately $4.6 million or approximately 4.2 percent, subject to refund. On September 6, 2017, the NDPSC approved the request for interim rates effective with service rendered on or after September 19, 2017. This matter is pending before the NDPSC.

On August 31, 2017, Cascade filed an application with the WUTC for a natural gas rate increase of approximately $5.9 million annually or approximately 2.7 percent above current rates. The requested increase includes costs associated with increased infrastructure investment and the associated operating expenses. Also included in the request is recovery of operation and maintenance costs associated with a maximum allowable operating pressure validation plan. This matter is pending before the WUTC.

On September 1, 2017, Montana-Dakota submitted an update to its transmission formula rate under the MISO tariff, which reflects an incremental increase of approximately $2.5 million to include a revenue requirement for the Company's multivalue project, for a total of $13.6 million effective January 1, 2018.

On September 25, 2017, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase of approximately $2.8 million annually or approximately 4.1 percent above current rates. The requested increase is primarily to recover the increased investment in distribution facilities to enhance system safety and reliability and the depreciation and taxes associated with the increase in investment. Montana-Dakota is also introducing an SSIP and the proposed adjustment mechanism required to fund the SSIP. Montana-Dakota requested an interim increase of approximately $1.6 million or approximately 2.3 percent, subject to refund. This matter is pending before the MTPSC.

On September 29, 2017, Cascade filed an application with the OPUC for an annual pipeline replacement safety cost recovery mechanism of approximately $784,000 or approximately 1.2 percent of additional revenue. The requested increase includes incremental pipeline replacement investments associated with qualifying pipeline integrity projects. If approved, rates will be effective January 1, 2018. This matter is pending before the OPUC.

Montana-Dakota previously filed an application with the NDPSC on October 14, 2016, for an electric rate increase which also included a requested return on equity to be used in the determination of applications previously filed by Montana-Dakota for a renewable resource cost adjustment rider, an electric generation resource recovery rider, and a transmission cost adjustment ~~rider.~~rider, as discussed in the following paragraphs. On April 7, 2017, Montana-Dakota, the NDPSC Advocacy Staff and the interveners in the case filed a settlement agreement resolving all issues in the general rate case. The settlement agreement included a net increase of approximately $7.5 million or 3.7 percent above previously approved final rates and a true-up of the return on equity used in the interim renewable resource cost adjustment, the electric generation resource recovery and transmission cost adjustment riders of 9.45 percent; a return on equity of 9.65 percent for base rates and the renewable resource cost adjustment rider on a go-forward basis; and a return on equity of 9.45 percent through December 31, 2019, for the natural gas-fired internal combustion engines and associated facilities included in the electric generation resource recovery rider. IfA hearing on the settlement agreement ~~is approved by~~was held on April 10, 2017. On June 16, 2017, the NDPSC approved the settlement agreement. On June 26, 2017, Montana-Dakota submitted a compliance filing and on July 14, 2017, submitted updated tariff sheets and a refund plan. The NDPSC approved the compliance filing and refund plan on July 26, 2017, with final

rates ~~will be~~effective with service rendered on or after August 7, 2017. The final rates are less than the interim rates currently in effect. Therefore, Montana-Dakota will refund the difference to customers, which is approximately 19 percent of the amount collected from the general rate case interim increase, along with refunds ~~if any,~~ to reflect true-ups for the various riders. The amount of refunds, less amounts previously accrued, are not expected to be material to the consolidated financial statements. A hearing on the settlement was held on April 10, 2017. This matter is pending before the NDPSC.riders, as applicable. The background information related to the settlement agreement and related applications are discussed in the following paragraphs.

On October 26, 2015, Montana-Dakota filed an application with the NDPSC requesting a renewable resource cost adjustment rider for the recovery of the Thunder Spirit Wind project. On January 5, 2016, the NDPSC approved the rider to be effective January 7, 2016, resulting in an annual increase on an interim basis, subject to refund, of $15.1 million based upon a 10.5 percent return on ~~equity.~~equity to be finalized upon approval of the electric rate case filed on October 14, 2016. The ~~interim~~electric rate ~~is pending the determination of the~~case settlement agreement filed on April 7, 2017, included a revised return on equity infor the ~~general rate case application filed October 14, 2016,~~rider. The settlement agreement was approved on June 16, 2017, as previously discussed in this note.

On October 26, 2015, Montana-Dakota filed an application with the NDPSC for an update to the electric generation resource recovery rider. On March 9, 2016, the NDPSC approved the rider to be effective with service rendered on and after March 15, 2016, which resulted in interim rates, subject to refund, of $9.7 million based upon a 10.5 percent return on ~~equity.~~equity to be finalized upon the approval of the electric rate case filed on October 14, 2016. The interim rates include recovery of Montana-Dakota's investment in the 88-MW simple-cycle natural gas turbine and associated facilities near Mandan, North Dakota, and the 19 MW of new generation from natural gas-fired internal combustion engines and associated facilities near Sidney, Montana. The electric rate case settlement agreement filed on April 7, 2017, included the net investment authorized for the natural gas-fired internal combustion engines and the return on equity on both ~~investments are pending the general rate case application filed October 14, 2016,~~investments. The settlement agreement was approved on June 16, 2017, as previously discussed in this note.

On November 25, 2015, Montana-Dakota filed an application with the NDPSC for an update of its transmission cost adjustment rider for recovery of MISO-related charges and two transmission projects in North Dakota. On February 10, 2016, the NDPSC

approved the transmission cost adjustment effective with service rendered on and after February 12, 2016, resulting in an annual increase on an interim basis, subject to refund, of $6.8 million based upon a 10.5 percent return on ~~equity.~~equity to be finalized upon approval of the electric rate case filed on October 14, 2016. The ~~interim~~electric rate ~~is pending the determination of the~~case settlement agreement filed on April 7, 2017, included a revised return on equity infor the ~~general rate case application filed October 14, 2016,~~rider. The settlement agreement was approved on June 16, 2017, as previously discussed in this note.

On October 14, 2016, Montana-Dakota filed an application with the NDPSC for an electric rate increase of approximately $13.4 million annually or 6.6 percent above current rates. The request includes rate recovery associated with increased investment in facilities, along with the related depreciation, operation and maintenance expenses and taxes associated with the increased investment. Montana-Dakota requested an interim increase of approximately $13.0 million or approximately 6.5 percent, subject to refund, to be effective within 60 days of the filing. On November 21, 2016, Montana-Dakota filed and on November 30, 2016, the NDPSC approved a revised interim increase of approximately $11.7 million, based on adjustments accepted by the NDPSC, or approximately 5.8 percent above current rates, subject to refund, effective with service rendered on or after December 13, 2016. ~~This matter is pending the approval of the~~A settlement agreement ~~by the NDPSC,~~was filed on April 7, 2017, and subsequently approved on June 16, 2017, as previously ~~discussed.~~discussed in this note.

Note 16 - Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated ~~subsidiaries.~~subsidiaries, which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. Accruals are based on the best information available, but in certain situations management is unable to estimate an amount or range of a reasonably possible loss including, but not limited to when: (1) the damages are unsubstantiated or indeterminate, (2) the proceedings are in the early stages, (3) numerous parties are involved, or (4) the matter involves novel or unsettled legal theories. The Company ~~had~~ accrued liabilities of ~~$29.1~~$34.3 million, ~~$19.0~~$20.0 million and $31.8 million, which ~~include~~have not been discounted, including liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, ~~respectively, including~~respectively. This includes amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

~~Natural Gas Gathering Operations~~ Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a gathering contract with Omimex as a result of the increased operating pressures demanded by a third party on a natural gas gathering system in Montana. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and, subject to final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013. On December 9, 2014, the United States District Court for the District of Montana issued an order determining WBI Energy Midstream breached its obligations as a common carrier and ordered judgment in favor of Omimex for the amount of the stipulated damages. WBI Energy Midstream filed an appeal from the United States

District Court for the District of Montana's order and judgment. The parties reached a settlement of the matter in March 2017. The settlement provides for a payment by WBI Energy Midstream of an amount that is not material to the Company.

The Company ~~also is subject~~will continue to ~~other litigation,~~monitor each matter and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals areadjust accruals as might be warranted based on ~~the best~~new information ~~available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management~~and further developments. Management believes that the outcomes with respect to ~~the above issues and other~~ probable and reasonably possible losses in excess of the amounts accrued, net of insurance recoveries, while uncertain, either can not be estimated or will not have a material effect upon the Company's financial position, results of operations or cash flows. Unless otherwise required by GAAP, legal costs are expensed as they are incurred.

Construction Services Capital Electric provided employees in 2012 to perform work for a contractor on a project in Kansas. One of the Capital Electric employees was injured while working on the project and brought a lawsuit against the contractor. Judgment was entered in favor of the employee and his spouse on November 3, 2016, in the amount of $44.8 million following a court determination that the employee’s injuries were caused by the contractor’s negligence. The contractor claims that Capital Electric was contractually required, but failed, to name the contractor as an additional insured under any liability policy in effect at the time of the project and that such failure resulted in the entry of judgment against the contractor. In March 2017, Capital Electric filed a petition for declaratory judgment in the District Court of Wyandotte County, Kansas for a judicial determination that any agreement between Capital Electric and the contractor for the project did not require Capital Electric to include the contractor as an additional insured under any liability policy issued to Capital Electric and that if such an agreement was found to exist, it would be void and unenforceable under Kansas law. The matter is pending before the District Court of Wyandotte County, Kansas and no accrual has been recorded for it.

Environmental matters

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $100 million. On January 6, 2017, Region 10 of the EPA issued a ROD with its selected remedy for cleanup of the in-river portion of the site. Implementation of the remedy is expected to take up to 13 years with a present value cost estimate of approximately $1 billion. Corrective action will not be taken until remedial design/remedial action plans are approved by the EPA. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to

facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife River - Northwest does not believe it is a responsible party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.

The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced matter.

Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors.

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. ~~Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million.~~ The Oregon DEQ released a ROD in January 2015 that selected a remediation alternative for the site as recommended in an earlier staff report. The total estimated cost for the selected remediation, including long-term maintenance, is approximately $3.5 million of which $320,000 has been incurred. It is not known at this time what share of the cleanup costs will actually be borne by Cascade; however, Cascade has paid 50 percent of the ongoing investigation and design costs and anticipates its proportional share of the final costs could be approximately 50 percent. Cascade has ~~accrued~~an accrual balance of $1.6 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received orders reauthorizing the deferred accounting for the 12-month periods starting November 30, 2013, December 1, 2014, December 1, 2015 and December 1, ~~2015. Cascade has requested authority to defer accounting for the 12-month period starting December 1, 2016, which is pending before the OPUC.~~2016.

The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. The EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. In April 2010, the Washington DOE issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a

remedial investigation and feasibility study for the site. Current estimates for the cost to complete the remedial investigation and feasibility study are approximately $7.6 million of which $700,000 has been incurred. Cascade has accrued ~~$12.4~~$6.9 million for the remedial investigation and feasibility study ~~and~~as well as $6.4 million for remediation of this ~~site.~~site; however, the accrual for remediation costs will be reviewed and adjusted, if necessary, after completion of the remedial investigation and feasibility study. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington DOE for completion of a remedial investigation and feasibility study for the site. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas. Cascade has not recorded an accrual for this site.

Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, Cascade intends to seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. The accruals related to these matters are reflected in regulatory assets.

In June 2016, WBI Energy sold all of the outstanding membership interests in Dakota Prairie Refining. In connection with the sale, Centennial agreed to continue to guarantee certain debt obligations of Dakota Prairie Refining which totaled ~~$62.6~~$57.4 million at ~~March 31,~~September 30, 2017, and are expected to mature by 2023. Tesoro agreed to indemnify Centennial for any losses and litigation expenses arising from the guarantee. The estimated fair values of the indemnity asset and guarantee liability are reflected in deferred charges and other assets - other and deferred credits and other liabilities - other, respectively, on the Consolidated Balance Sheets. Continuation of the guarantee was required as a condition to the sale of Dakota Prairie Refining.

In March 2016, a sale agreement was signed to sell Fidelity's assets in the Paradox Basin. In connection with the sale, Centennial agreed to guarantee Fidelity's indemnity obligations associated with the Paradox assets. The guarantee was required by the buyer as a condition to the sale of the Paradox Basin assets.

In 2009, multiple sale agreements were signed to sell the Company's ownership interests in the Brazilian Transmission Lines. In connection with the sale, Centennial agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who were the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, insurance deductibles and loss limits, and certain other guarantees. At ~~March 31,~~September 30, 2017, the fixed maximum amounts guaranteed under these agreements aggregated ~~$92.8~~$119.4 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate ~~$8.3~~$2.5 million in 2017; ~~$26.2~~$21.3 million in 2018; ~~$54.3~~$15.8 million in 2019; $72.6 million in 2020; $500,000 in 2021; $2.7 million thereafter; and $4.0 million, which has no scheduled maturity date. There were no amounts outstanding under the above guarantees at ~~March 31,~~September 30, 2017. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At ~~March 31,~~September 30, 2017, the fixed maximum amounts guaranteed under these letters of credit aggregated ~~$31.0~~$34.0 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate ~~$30.3~~$29.2 million in 2017 and ~~$700,000~~$4.8 million in 2018. There were no amounts outstanding under the above letters of credit at ~~March 31,~~September 30, 2017. In the event of default under these letter of credit obligations, the subsidiary issuing the letter of credit for that particular obligation would be required to make payments under its letter of credit.

In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River or MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at ~~March 31,~~September 30, 2017.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire

within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At ~~March 31,~~September 30, 2017, approximately ~~$744.0~~$556.8 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

Variable interest entities

The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary.

~~Dakota Prairie Refining, LLC~~On February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each had a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement were $150 million and $75 million, respectively. Capital commitments in excess of $300 million were shared equally between WBI Energy and Calumet. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The operating agreement provided for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt was allocated to Calumet. Calumet's cash distributions from Dakota Prairie Refining were decreased by the principal and interest paid on the project debt, while the cash distributions to WBI Energy were not decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan. The net loss attributable to noncontrolling interest on the Consolidated Statements of Income is pretax as Dakota Prairie Refining was a limited liability company. For more information related to the guarantee, see Guarantees in this note.

Dakota Prairie Refining was determined to be a VIE, and the Company had determined that it was the primary beneficiary as it had an obligation to absorb losses that could have been potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidated Dakota Prairie Refining in its financial statements and recorded a noncontrolling interest for Calumet's ownership interest.

On June 24, 2016, WBI Energy entered into a membership interest purchase agreement with Tesoro to sell all of the outstanding membership interests in Dakota Prairie Refining to Tesoro. To effectuate the sale, WBI Energy acquired Calumet’s 50 percent membership interest in Dakota Prairie Refining on June 27, 2016. The sale of the membership interests to Tesoro closed on June 27, 2016. For more information on the Company's discontinued operations, see Note 8.

Dakota Prairie Refinery commenced operations in May 2015. The assets of Dakota Prairie Refining were used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining were as follows:

Fuel Contract Coyote Station entered into a coal supply agreement with Coyote Creek that provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for ~~the period~~ May 2016 through December 2040. Coal purchased under the coal supply agreement is reflected in inventories on the Company's Consolidated Balance Sheets and is recovered from customers as a component of electric fuel and purchased power.

The coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.

At ~~March 31,~~September 30, 2017, the Company's exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, was ~~$42.7~~$41.4 million.

~~Note 17 - Subsequent events~~

On March 1, 2017, the Company provided notice of its intent to redeem all outstanding shares of its preferred stock. Effective April 1, 2017, all outstanding preferred stock was redeemed for a repurchase price of approximately ~~$15.9 million. The redemption of the preferred stock was funded with borrowings from the Company's commercial paper program and cash on hand.~~

~~On April 25, 2017, Cascade amended its revolving credit agreement to increase the borrowing limit to $75.0 million and extend the termination date to April 24, 2020.~~

~~On April 25, 2017, Intermountain amended its revolving credit agreement to increase the borrowing limit to $85.0 million and extend the termination date to April 24, 2020.~~

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The Company's strategy is to apply its expertise in the regulated energy delivery and construction materials and services businesses to increase market share, increase profitability and enhance shareholder value through:

~~Divestiture of certain assets to fund capital growth projects throughout the Company~~

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities, the issuance from time to time of debt and equity securities and asset sales. For more information on the Company's capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's ~~businesses,~~business segments, see Note 13.

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide safe and reliable competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation and transmission and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and timely recovery and permitted returns on investment as well as subject to certain operational, system integrity and environmental regulations. These regulations can require substantial investment to upgrade facilities. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service facilities is subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which will necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas and could result in the retirement of certain electric generating facilities before they are fully depreciated.

Pipeline and Midstream

Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and investments in and acquisitions of energy-related assets and companies ~~both~~ in its current operating ~~areas and beyond its Rocky Mountain and northern Great Plains base.~~areas. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing storage, gathering and transmission facilities; incremental pipeline projects which expand pipeline capacity; and expansion of the pipeline and midstream business to include liquid pipelines and processing activities.

ChallengesOngoing challenges for this segment include: energy price volatility; basis differentials; environmental and regulatory requirements; securing permits and easements; recruitment and retention of a skilled workforce; and competition from other pipeline and midstream companies.

Construction Materials and Contracting

Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.

Challenges Recruitment and retention of key personnel and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, are ongoing challenges. This business unit expects to continue cost containment efforts, positioning its operations for the resurgence in the private market, while continuing the emphasis on industrial, energy and public works projects.

Construction Services

Strategy Provide a superior return on investment by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; growing through organic and acquisition opportunities; and focusing efforts on projects that will permit higher margins while properly managing risk.

Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges.

Additional Information

For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Part II, Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2016 Annual Report. For more information on key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements.

The following table summarizes the contribution to the consolidated earnings (loss) by each of the Company's businesses.

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 The Company recognized consolidated earnings of ~~$37.2~~$87.4 million for the quarter ended ~~March 31,~~September 30, 2017, compared to ~~$24.7~~$82.8 million from the comparable prior period largely due to:

These increases were partially offset by:

Nine Months Ended September 30, 2017 and 2016 The Company recognized consolidated earnings of $165.1 million for the nine months ended September 30, 2017, compared to a consolidated loss of $1.8 million from the comparable prior period largely due to:

These increases were partially offset by:

Financial and Operating Data

Below are key financial and operating data for each of the Company's businesses.

Electric


	Three Months Ended				Three Months Ended				Nine Months Ended
	March 31,				September 30,
	2017		2016		2017		2016		2017		2016
	(Dollars in millions, where applicable)				(Dollars in millions, where applicable)
Operating revenues	$	88.2	$	82.9	$	91.5	$	82.2	$	254.3	$	238.9
Operating expenses:
Fuel and purchased power	21.9		22.0
Operation and maintenance	28.2		26.9		30.4		28.9		87.5		84.7
Electric fuel and purchased power					18.9		16.8		57.5		54.7
Depreciation, depletion and amortization	11.8		12.9		12.2		12.5		35.5		37.8
Taxes, other than income	3.5		3.4		3.7		3.6		11.1		10.2
	65.4		65.2		65.2		61.8		191.6		187.4
Operating income	22.8		17.7		26.3		20.4		62.7		51.5
Earnings	$	14.3	$	11.1	$	15.7	$	12.7	$	37.9	$	31.8
Retail sales (million kWh):
Residential	355.8		323.6		278.7		276.6		860.2		835.7
Commercial	397.0		373.7		377.7		373.3		1,122.7		1,089.5
Industrial	141.9		143.7		133.7		126.0		395.9		401.9
Other	22.3		21.4		28.5		23.3		75.7		66.5
	917.0		862.4		818.6		799.2		2,454.5		2,393.6
Average cost of fuel and purchased power per kWh	$	.022	$	.024
Average cost of electric fuel and purchased power per kWh					$	.021	$	.019	$	.022	$	.021

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Electric earnings increased ~~$3.2~~$3.0 million ~~(29~~(24 percent) ~~due to:~~

Partially offsetting the increase were:

Nine Months Ended September 30, 2017 and 2016 Electric earnings increased $6.1 million (19 percent) compared to the comparable prior period due to:

Partially offsetting ~~the earnings increase was higher~~these increases were:

Natural Gas Distribution



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(Dollars in millions, where applicable)
Operating revenues	$	92.3		$	87.9		$	566.4		$	500.1
Operating expenses:
Operation and maintenance	39.6			39.5			119.2			116.6
Purchased natural gas sold	36.4			37.6			314.9			273.7
Depreciation, depletion and amortization	17.4			16.6			51.7			49.6
Taxes, other than income	8.2			8.0			37.3			34.3
	101.6			101.7			523.1			474.2
Operating income (loss)	(9.3		)	(13.8		)	43.3			25.9
Earnings (loss)	$	(10.9	)	$	(12.5	)	$	14.2		$	4.9
Volumes (MMdk)
Sales:
Residential	3.9			3.9			40.4			34.2
Commercial	4.0			3.8			29.0			24.5
Industrial	.8			.8			3.3			3.0
	8.7			8.5			72.7			61.7
Transportation:
Commercial	.3			.3			1.4			1.2
Industrial	35.8			37.3			102.1			108.2
	36.1			37.6			103.5			109.4
Total throughput	44.8			46.1			176.2			171.1
Degree days (% of normal)*
Montana-Dakota/Great Plains	242		%	174		%	99		%	84		%
Cascade	80		%	93		%	110		%	80		%
Intermountain	178		%	147		%	113		%	94		%
Average cost of natural gas, including transportation, per dk	$	4.20		$	4.44		$	4.33		$	4.44

Three Months Ended
March 31,
2017
2016
(Dollars in millions, where applicable)
Operating revenues $ 342.5
$ 299.4
Operating expenses:

Purchased natural gas sold 214.4
182.1
Operation and maintenance 40.9
38.8
Depreciation, depletion and amortization 17.1
16.4
Taxes, other than income 18.6
16.7
291.0
254.0
Operating income 51.5
45.4
Earnings $ 27.9
$ 25.2
Volumes (MMdk)

Sales:
Residential 28.1
23.4
Commercial 19.0
15.6
Industrial 1.6
1.3
48.7
40.3
Transportation:
Commercial .7
.6
Industrial 38.0
40.7
38.7
41.3
Total throughput 87.4
81.6
Degree days (% of normal)*

Montana-Dakota/Great Plains 98 % 81 %
Cascade 117 % 87 %
Intermountain 109 % 95 %
Average cost of natural gas, including transportation, per dk $ 4.40
$ 4.52

* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Natural gas distribution experienced a seasonal loss of $10.9 million compared to a seasonal loss of $12.5 million a year ago (13 percent improvement). The improvement was the result of higher natural gas retail sales margins due to approved rate recovery, weather normalization and conservation adjustments to offset warmer weather in certain jurisdictions and higher retail sales volumes of 2 percent to commercial and residential classes, primarily resulting from colder weather in certain jurisdictions and customer growth.

Partially offsetting the increase were:

Lower tax credits of $500,000

Higher depreciation, depletion and amortization expense of $500,000 (after tax) due to increased property, plant and equipment balances

Nine Months Ended September 30, 2017 and 2016 Natural gas distribution earnings increased ~~$2.7~~$9.3 million ~~(10~~(187 percent) compared to the comparable prior period due ~~to higher~~to:

Higher natural gas retail sales margins resulting from higher retail sales volumes of 2118 percent to all customer classes, driven primarily ~~increased customers and~~by colder weather in all ~~regions served,~~jurisdictions and customer growth, as well as approved rate ~~recovery.~~recovery; offset in part by weather normalization and conservation adjustments in certain jurisdictions

Higher natural gas transportation margins resulting from higher average rates due to customer mix, partially offset by a decrease in volumes of 6 percent

Partially offsetting ~~the increase~~these increases were:

Higher operation and maintenance expense, which includes ~~$1.4~~$1.8 million (after tax) ~~largely the result of~~primarily due to higher payroll-related costs ~~timing of software maintenance costs and bad debt expense~~

Higher depreciation, depletion and amortization expense of ~~$400,000~~$1.3 million (after tax) due to increased property, plant and equipment balances

Pipeline and Midstream


	Three Months Ended						Three Months Ended				Nine Months Ended
	March 31,						September 30,
	2017			2016			2017		2016		2017		2016
	(Dollars in millions)						(Dollars in millions)
Operating revenues	$	28.0		$	33.4		$	31.6	$	36.0	$	89.9	$	105.8
Operating expenses:
Operation and maintenance	13.5			13.8			13.7		14.1		40.9		43.1
Depreciation, depletion and amortization	4.1			6.2			4.2		6.2		12.4		18.5
Taxes, other than income	3.0			2.8			3.1		3.0		9.2		8.9
	20.6			22.8			21.0		23.3		62.5		70.5
Operating income	7.4			10.6			10.6		12.7		27.4		35.3
Earnings	$	3.9		$	5.3		$	6.0	$	6.7	$	15.1	$	18.3
Transportation volumes (MMdk)	67.1			75.3			82.4		67.7		228.9		217.1
Natural gas gathering volumes (MMdk)	3.9			4.9			4.1		5.1		12.1		15.0
Customer natural gas storage balance (MMdk):
Beginning of period	26.4			16.6			25.1		28.1		26.4		16.6
Net withdrawal	(11.4		)	(2.1		)
Net injection							9.5		7.2		8.2		18.7
End of period	15.0			14.5			34.6		35.3		34.6		35.3

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Pipeline and midstream earnings decreased ~~$1.4 million (26~~$700,000 (11 percent) compared to the comparable prior period. The decrease was primarily the result ~~of:~~

~~Lower~~of lower gathering and processing ~~earnings~~revenues of ~~$3.2~~$3.6 million (after tax), ~~primarily~~largely due to lower volumes resulting from the sale of Pronghorn in January ~~2017, as well as normal declines and lower gathering rates in certain operating areas~~

~~Lower transportation earnings due to lower transportation volumes, largely offset by increased firm contract demand revenue~~2017.

Partially offsetting the ~~decreases~~decrease were:

Lower depreciation, depletion and amortization expense of ~~$1.3~~$1.2 million (after tax), primarily due to the absence of Pronghorn

Higher transportation revenues of $800,000 (after tax), largely due to increased off-system transportation which reflects increased volumes due to recently completed organic growth projects and higher volumes transported to storage

Lower operation and maintenance expense primarily due to lower payroll-related costs and the absence of Pronghorn

Lower interest expense of ~~$600,000~~$400,000 (after tax) due to lower debt balances

Nine Months Ended September 30, 2017 and 2016 Pipeline and midstream earnings decreased $3.2 million (17 percent) compared to the comparable prior period. The decrease was primarily the result of lower gathering and processing revenues of $10.3 million (after tax), largely due to lower volumes resulting from the sale of Pronghorn, as well as lower gathering rates in certain operating areas.

Partially offsetting the decrease were:

Lower depreciation, depletion and amortization expense of $3.8 million (after tax), primarily due to the absence of Pronghorn

Lower operation and maintenance expense primarily due to the absence of Pronghorn and lower payroll-related costs

Lower interest expense of $1.5 million (after tax) due to lower debt balances

Construction Materials and Contracting


	Three Months Ended						Three Months Ended				Nine Months Ended
	March 31,						September 30,
	2017			2016			2017		2016		2017		2016
	(Dollars in millions)						(Dollars in millions)
Operating revenues	$	200.9		$	210.0		$	686.1	$	724.7	$	1,388.6	$	1,476.0
Operating expenses:
Operation and maintenance	205.8			204.7			555.2		582.2		1,198.3		1,243.4
Depreciation, depletion and amortization	13.7			15.1			14.0		14.4		42.1		44.3
Taxes, other than income	9.0			9.6			12.0		12.2		32.9		33.7
	228.5			229.4			581.2		608.8		1,273.3		1,321.4
Operating loss	(27.6		)	(19.4		)
Loss	$	(19.9	)	$	(14.5	)
Operating income							104.9		115.9		115.3		154.6
Earnings							$	63.2	$	69.5	$	64.5	$	88.8
Sales (000's):
Aggregates (tons)	3,505			3,626			10,078		9,997		20,957		21,281
Asphalt (tons)	215			239			3,009		3,507		5,054		5,959
Ready-mixed concrete (cubic yards)	562			644			1,098		1,146		2,697		2,840

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Construction materials and contracting ~~experienced a seasonal first quarter loss of $19.9~~earnings decreased $6.3 million (9 percent) compared to ~~a loss of $14.5 million a year ago (38 percent increased loss)~~the comparable prior period due to:

Partially offsetting these decreases were:

Nine Months Ended September 30, 2017 and 2016 Construction materials and contracting earnings decreased $24.3 million (27 percent) compared to the comparable prior period due to:

Partially offsetting these decreases was higher ~~earnings~~aggregate margins of ~~$1.1~~$1.6 million (after tax) resulting from ~~higher aggregate margins largely due to~~ lower production costs and strong commercial and residential demand in certain regions.

Construction Services

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Construction services earnings increased ~~$1.4~~$5.9 million ~~(23~~(82 percent) compared to the comparable prior period due to:

Partially offsetting these increases was higher selling, general and administrative expense of ~~project startup~~$1.2 million (after tax), primarily higher payroll-related costs.

Nine Months Ended September 30, 2017 and ~~successful execution of labor activity on projects under full construction~~2016 Construction services earnings increased $12.7 million (63 percent) compared to the comparable prior period due to:

Partially offsetting ~~the~~these increases were:

~~Higher selling, general and administrative expense of $1.0 million (after tax), largely due to higher payroll-related costs~~

Included in Other are general and administrative costs and interest expense previously allocated to the exploration and production and refining businesses that do not meet the criteria for income (loss) from discontinued operations.

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 Other experienced earnings of $600,000 compared to a loss ~~decreased $1.2~~of $1.0 million in the comparable prior period. The increase was primarily due to lower operation and maintenance expense of $1.5 million (after tax), largely due to the ~~result~~absence of general and administrative costs previously allocated to the refining business due to the sale of the business in June 2016 and lower insurance costs. Also contributing to the increase was lower interest expense due to the repayment of long-term debt with the sale of the remaining exploration and production ~~assets~~assets.

Nine Months Ended September 30, 2017 and 2016 Other loss decreased $1.7 million compared to the comparable prior period primarily due to lower interest expense, which includes $1.4 million (after tax) largely due to the repayment of long-term debt, as previously discussed. Also contributing to the increase was lower operation and maintenance expense due to lower general and administrative costs previously allocated to the refining business, ~~due to~~as previously discussed, offset in part by a loss on the ~~sale~~disposition of ~~this business in 2016.~~certain assets.

Discontinued Operations

Three Months Ended
March 31,
2017
2016
(In millions)
Income (loss) from discontinued operations before intercompany eliminations, net of tax $ 3.9
$ (18.1 )
Intercompany eliminations (2.2 ) * .1
Income (loss) from discontinued operations, net of tax 1.7
(18.0 )
Loss from discontinued operations attributable to noncontrolling interest —
(11.1 )
Income (loss) from discontinued operations attributable to the Company, net of tax $ 1.7
$ (6.9 )



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In millions)
Income (loss) from discontinued operations before intercompany eliminations, net of tax	$	(.3	)	$	.2		$	2.4		$	(303.0	)
Intercompany eliminations*	(1.9		)	(5.6		)	(6.1		)	3.5
Loss from discontinued operations, net of tax	(2.2		)	(5.4		)	(3.7		)	(299.5		)
Loss from discontinued operations attributable to noncontrolling interest	—			—			—			(131.7		)
Loss from discontinued operations attributable to the Company, net of tax	$	(2.2	)	$	(5.4	)	$	(3.7	)	$	(167.8	)

* Includes ~~an elimination~~eliminations for the presentation of income tax adjustments between continuing and discontinued operations.

Three Months Ended ~~March 31,~~September 30, 2017 and 2016 The Company's ~~income~~loss from discontinued operations was ~~$1.7~~$2.2 million compared to a loss of ~~$6.9~~$5.4 million for the comparable prior period as a result of lower income tax adjustments.

Nine Months Ended September 30, 2017 and 2016 The Company's loss from discontinued operations was $3.7 million compared to a loss of $167.8 million for the comparable prior period. The ~~increase~~decreased loss was largely due to the absence in 2017 of a loss atassociated with the sale of the refining ~~business which was sold in June 2016, as well as the reversal in 2017 of a previously accrued liability due to the resolution of a legal matter.~~business.

Intersegment Transactions

Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of intersegment transactions. The amounts relating to these items are as follows:


	Three Months Ended						Three Months Ended						Nine Months Ended
	March 31,						September 30,
	2017				2016		2017			2016			2017			2016
	(In millions)						(In millions)
Intersegment transactions:
Operating revenues	$	23.4			$	23.5	$	5.6		$	5.7		$	37.6		$	37.6
Operation and maintenance							2.5			2.4			6.6			6.7
Purchased natural gas sold	21.5				21.1		3.1			3.3			31.0			30.9
Operation and maintenance	1.9				2.4
Income from continuing operations	(2.2		)	*	—
Income from continuing operations*							(1.9		)	(5.6		)	(6.1		)	(5.6		)

* Includes ~~an elimination~~eliminations for the presentation of income tax adjustments between continuing and discontinued operations.

For more information on intersegment eliminations, see Note 13.

Prospective Information

The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain of the Company's businesses. Many of these highlighted points are "forward-looking statements." There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section and the various important factors listed in Part II, Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2016 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.

MDU Resources Group, Inc.

The Company continually seeks opportunities to expand through organic growth opportunities and strategic acquisitions.

The Company focuses on creating value through vertical integration within and among its business units.

Electric and natural gas distribution

than 99 percent of the necessary easements have been secured. The Company's total capital investment in this project is expected to be in the range of $150 million to $170 million. The Company expects this project to be completed in 2019.

•

The Company expects to grow its rate base by approximately 4 percent annually over the next five years on a compound basis. This growth projection is on a much larger base, having grown rate base at a record pace of 12 percent compounded annually over the past five-year period. The utility operations are spread across eight states where customer growth is expected to be higher than the national average. This customer growth, along with system upgrades and replacements needed to supply safe and reliable service, will require investments in new electric generation and transmission, and electric and natural gas distribution. Rate base at December 31, 2016, was $1.9 billion.


•	The Company expects its customer base to grow by 1 percent to 2 percent per year.

•

In June 2016, the Company, along with a partner, began a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The project has been approved as a MISO multivalue project. All of the necessary easements have been secured. The Company's total capital investment in this project is expected to be in the range of $150 million to $170 million. The Company expects this project to be completed in 2019.

In December 2016, the Company signed a 25-year agreement to purchase ~~the~~ power from the expansion of the Thunder Spirit Wind farm in southwest North Dakota. The agreement ~~also~~ includes an option to buy the project at the close of construction. The expansion of the Thunder Spirit Wind farm will boost the combined production at the wind farm to approximately 150 MW of renewable energy and, if purchased, will increase the Company's generation portfolio from approximately 22 percent renewables to 27 percent. The original 107.5-MW Thunder Spirit Wind farm includes 43 turbines; it was purchased by the Company in December 2015. The expansion ~~includes 13 to~~will include 16 turbines, ~~depending on the turbine size selected. It~~and is expected to be ~~online~~on line in December 2018. ~~Construction~~Acquisition costs for the project are estimated to be $85 million. In June 2017, the Company filed with the NDPSC a request for an advance determination of prudence for the purchase of this expansion.

The Company ~~is in the process of completing~~filed its 2017 ~~electric integrated resource plan~~North Dakota Electric Integrated Resource Plan and ~~is evaluating its future generation~~2017 Montana Electric Integrated Resource Plan in June 2017 and ~~power supply portfolio options, including~~September 2017, respectively. The plans include the proposed purchase of the Thunder Spirit Wind farm expansion project and the development and design of a ~~large-scale resource. The plan will~~large combined-cycle, natural gas-fired facility to be ~~finalized and filed by mid-2017.~~expected in 2025 or later.

~~The Company is involved with~~


•	The Company is involved in a number of natural gas pipeline projects to enhance the safety, reliability and deliverability of its system.

The Company is focused on organic growth, while monitoring potential merger and acquisition opportunities.

~~Regulatory actions~~

~~Completed Cases:~~

The Company continues to be focused on the regulatory recovery of its investments. Since January 1, ~~2015,~~2017, the Company has implemented final rate increases totaling ~~$61.6~~$37.3 million in annual revenue. This includes electric rate proceedings in Montana, North Dakota, South Dakota, Wyoming and before the FERC, and natural gas proceedings in Idaho, Minnesota, Montana, ~~North Dakota,~~ Oregon ~~South Dakota, Washington~~ and ~~Wyoming.~~Washington. Recently ~~implemented~~approved final rates include:


◦	On ~~June 10, 2016,~~September 1, 2017, the Company ~~filed~~submitted an ~~application for an increase in electric rates with~~update to its transmission formula rate under the ~~WYPSC,~~MISO tariff, as discussed in Note 15.


◦	On September 14 2017, the IPUC approved the natural gas rate increase filed by the Company on August 12, 2016, as discussed in Note 15.


◦	On October 26, 2017, the WUTC approved the annual pipeline replacement cost recovery mechanism filed by the Company on May 31, 2017, as discussed in Note 15.

The Company is requesting rate increases totaling $15.4 million in annual revenue, which includes $4.6 million in implemented interim rates. Cases recently filed include:


◦	On July 21, 2017, the Company filed an application with the ~~IPUC~~NDPSC for a natural gas rate increase, as discussed in Note 15.


◦	On ~~April 1,~~August 31, 2017, the Company ~~implemented Phase 2 of~~filed an application with the ~~electric~~WUTC for a natural gas rate ~~case approved by the MTPSC,~~increase, as discussed in Note 15.

~~Pending Cases:~~

~~The Company is requesting rate increases totaling $39.6 million in annual revenue, which includes $39.1 million in implemented interim rates. Cases pending are:~~


◦	On ~~December 2, 2016,~~September 25, 2017, the Company filed an application with the MTPSC ~~requesting authority to implement~~for a natural gas ~~and electric tax tracking adjustments,~~rate increase, as discussed in Note 15.


◦	On ~~December 21, 2016,~~September 29, 2017, the Company filed an application with the ~~MNPUC requesting authority to implement a natural gas utility infrastructure~~OPUC for an annual pipeline replacement safety cost ~~tariff,~~recovery mechanism, as discussed in Note 15.

◦

The Company previously filed an application with the NDPSC on October 14, 2016, for an electric rate increase which also included a requested return on equity to be used in the determination of applications previously filed by the Company for a renewable resource cost adjustment rider, an electric generation resource recovery rider, and a transmission cost adjustment rider, as discussed in Note 15.

Pipeline and midstream

In September 2016, the Company secured sufficient capacity commitments and started survey work on a 38-mile pipeline that will deliver natural gas supply to eastern North Dakota and far western Minnesota. The Valley Expansion project will connect the Viking Gas Transmission Company pipeline near Felton, Minnesota, to the Company's existing pipeline near Mapleton, North Dakota. Cost of the expansion is estimated at $55 million to $60 million. The project, which is designed to transport 40 million cubic feet of natural gas per day, is under the jurisdiction of the FERC. In October 2016, the Company received FERC approval on its pre-filing for the Valley Expansion project. With minor enhancements, the pipeline will be able to transport significantly more volume if required, based on capacity requested or as needed in the future as the region's demand grows. Following receipt of necessary permits and regulatory approvals, construction is expected to begin in 2018 with completion expected in late 2018.


•	The ~~Company signed agreements to complete expansion projects, including the~~ Charbonneau and Line Section 25 expansion projects, which include a new compression station as well as other compression additions and enhancements at existing stations, were placed into service in the second quarter of 2017. The Company has signed long-term agreements supporting the expansion projects.

In June 2017, the Company announced plans to complete a Line Section 27 expansion project in ~~2016.~~the Bakken producing area in northwestern North Dakota. The ~~Charbonneau and Line Section 25 expansion~~ project will include aapproximately 13 miles of new ~~compression station~~pipeline and associated facilities. The project, as ~~well as other compression modifications~~designed, will increase capacity by over 200 million cubic feet per day and bring total capacity to over 600 million cubic feet per day. The project is expected to be placed in service in the ~~second quarter~~fall of ~~2017.~~

2018. The Company ~~continues~~has signed long-term contracts supporting this expansion and expects construction costs to ~~focus on growing and improving existing operations through organic projects~~range from $27 million to ~~become the leading pipeline company and midstream provider in all areas in which it operates.~~$30 million.


•	The Company continues to focus on growth and improving existing operations through organic projects and acquisitions in all areas in which it operates.

Construction materials and contracting

~~Approximate work backlog at March 31, 2017, was $725 million, compared to $831 million a year ago.~~

~~Projected revenues are in the range of $1.85 billion to $1.95 billion in 2017.~~


•	Approximate work backlog at September 30, 2017, was $520 million, compared to $580 million a year ago.


•	Projected revenues have been decreased from a range of $1.8 billion to $1.9 billion to a range of $1.7 billion to $1.8 billion for 2017.

The Company anticipates margins in 2017 to be slightly ~~higher~~lower as compared to 2016 margins.

~~In December 2015, Congress passed, and the president signed, a $305 billion, five-year highway bill for funding of transportation infrastructure projects that are a key part of the Company's market.~~


•	The Company expects public sector workload growth as anticipated new state and local infrastructure spending initiatives are introduced. California's $52.4 billion Road Repair and Accountability Act of 2017 and Oregon's $5.3 billion transportation package are expected to drive demand in both the near and far term in those states.

As one of the country's largest sand and gravel producers, the Company will continue to strategically manage its 1.0 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

Of the seven labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business Properties - General in the 2016 Annual Report, ~~three~~six have been ratified. The ~~four~~one remaining ~~contracts are~~contract is still in negotiations.

Construction services

~~Approximate work backlog at March 31, 2017, was $529 million, compared to $530 million a year ago.~~

~~Projected revenues are in the range of $1.0 billion to $1.1 billion in 2017.~~

~~The Company anticipates margins in 2017 to be comparable to 2016 margins.~~


•	Approximate work backlog at September 30, 2017, was $676 million, compared to $518 million a year ago.


•	Projected revenues have been increased from a range of $1.2 billion to $1.3 billion to a range of $1.25 billion to $1.35 billion for 2017.


•	The Company anticipates margins in 2017 to be comparable to 2016 margins.

The Company continues to pursue opportunities ~~for expansion in energy projects such as petrochemical,~~to provide service to the transmission, distribution, substations, utility services, industrial, commercial, high-technology, mission critical, manufacturing, institutional, hospitality, gaming, entertainment, infrastructure, and ~~renewables.~~renewable markets. Initiatives are aimed at capturing additional market share and expanding into new markets.

As the 13th-largest specialty contractor, the Company continues to pursue opportunities for expansion and execute initiatives in current and new markets that align with the Company's expertise, resources and strategic growth plan.

The five labor contracts that MDU Construction Services was negotiating, as reported in Items 1 and 2 - Business Properties - General in the 2016 Annual Report, have been ratified.

Liquidity and Capital Commitments

At ~~March 31,~~September 30, 2017, the Company had cash and cash equivalents of ~~$50.7~~$37.4 million and available borrowing capacity of ~~$652.3~~$663.3 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year and its other operating and capital requirements from various sources, including internally generated funds; the Company's credit facilities, as described in Capital resources; and through the issuance of long-term debt.

Cash flows

Operating activitiesThe changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital. Changes in cash flows for discontinued operations are related to the former exploration and production and refining businesses.

Cash flows provided by operating activities in the first ~~three~~nine months of 2017 ~~increased $41.0~~decreased $4.6 million from the comparable period in 2016. The ~~increase~~decrease in cash flows provided by operating activities was largely ~~from the absence in 2017 of the use of cash~~related to higher working capital requirements at the ~~exploration and production and refining businesses in 2016.~~construction services business resulting from higher workloads.

Investing activities Cash flows ~~provided by~~used in investing activities in the first ~~three~~nine months of 2017 ~~was $45.6~~decreased $155.4 million ~~compared to cash flows used~~from the comparable period in ~~investing activities of $79.5 million in the first three months of~~ 2016. The ~~change~~decrease was primarily due to net proceeds from the sale of Pronghorn at the pipeline and midstream business along with lower capital expenditures primarily at the electric and construction services businesses. Partially offsetting the ~~change~~decrease was the absence of net proceeds from the sale of property at the exploration and production business.

Financing activities Cash flows used in financing activities in the first ~~three~~nine months of 2017 ~~was $127.5~~increased $135.5 million ~~compared to cash flows provided by financing activities of $40.7 million~~from the comparable period in ~~the first three months of~~ 2016. The change was primarily due to lower issuance of long-term debt in 2017 of ~~$166.6~~$208.3 million. Partially offsetting the change was lower repayment of long-term debt along with the absence in 2017 of the debt repayment in connection with the sale of the refining business in 2016.

Defined benefit pension plans

There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the 2016 Annual Report. For more information, see Note 14 and Part II, Item 7 in the 2016 Annual Report.

Capital expenditures

Capital expenditures for the first ~~three~~nine months of 2017 were ~~$55.1 million and~~$217.1 million. Capital expenditures allocated to the Company's business segments are estimated to be approximately ~~$519.0~~$342 million for ~~2017. Estimated~~2017, which does not include additional growth capital of $150 million. The additional growth capital is not allocated to a specific business segment and will be invested based on the risk-adjusted return potential of opportunities and is dependent upon the timing of such opportunities. The estimated capital expenditures for 2017 include:

System upgrades

Routine replacements

Service extensions

Routine equipment maintenance and replacements

Buildings, land and building improvements

Pipeline, gathering and other midstream projects

Power generation and transmission opportunities

Environmental upgrades

Other growth opportunities

The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2017 capital expenditures referred to previously. The Company expects the 2017 estimated capital expenditures to be funded by various sources, including internally generated funds; the Company's credit facilities, as described in Capital resources; through the issuance of long-term debt; and asset sales.

Capital resources

Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at ~~March 31,~~September 30, 2017. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. For more information on the covenants, certain other conditions and cross-default provisions, see Part II, Item 8 - Note 6, in the 2016 Annual Report.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at ~~March 31,~~September 30, 2017:


Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
			(In millions)												(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	175.0		$	34.3	(b)	$	—		5/8/19	Commercial paper/Revolving credit agreement	(a)	$	175.0		$	43.4	(b)	$	—		5/8/19
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	—		$	2.2	(d)	7/9/18	Revolving credit agreement		$	75.0	(c)	$	10.0		$	2.2	(d)	4/24/20
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	—		$	—		7/13/18	Revolving credit agreement		$	85.0	(e)	$	39.9		$	—		4/24/20
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	101.2	(b)	$	—		9/23/21	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	76.2	(b)	$	—		9/23/21


(a)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $225.0 million). There were no amounts outstanding under the credit agreement.


(b)	Amount outstanding under commercial paper program.


(c)	Certain provisions allow for increased borrowings, up to a maximum of ~~$75.0~~$100.0 million.


(d)	Outstanding letter(s) of credit reduce the amount available under the credit agreement.


(e)	Certain provisions allow for increased borrowings, up to a maximum of ~~$90.0~~$110.0 million.


(f)	The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $600.0 million). There were no amounts outstanding under the credit agreement.

The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements. The commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of the construction businesses.

The following includes information related to the preceding table.

MDU Resources Group, Inc. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in the Company's credit ratings have not limited, nor are currently expected to limit, the Company's ability to access the capital markets. If the Company were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility become too expensive, which the Company does not currently anticipate, the Company would seek alternative funding.

The Company's coverage of earnings to fixed charges including preferred stock dividends was 4.1 times, ~~3.3~~3.7 times and 3.9 times for the 12 months ended ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, respectively.

Total equity as a percent of total capitalization was 5857 percent, 5655 percent and 56 percent at ~~March 31,~~September 30, 2017 and 2016, and December 31, 2016, respectively. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus total equity. This ratio is an indicator of how a company is financing its operations, as well as its financial strength.

Cascade Natural Gas Corporation On April 25, 2017, Cascade amended its revolving credit agreement to increase the borrowing limit from $50.0 million to $75.0 million and extend the termination date from July 9, 2018 to April 24, 2020. The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.

Cascade's credit agreement also contains cross-default provisions. These provisions state that if Cascade fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, Cascade will be in default under the revolving credit agreement.

Intermountain Gas Company On April 25, 2017, Intermountain amended its revolving credit agreement to increase the borrowing limit from $65.0 million to $85.0 million and extend the termination date from July 13, 2018 to April 24, 2020. The credit agreement contains customary covenants and provisions, including a covenant of Intermountain not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.

Intermountain's credit agreement also contains cross-default provisions. These provisions state that if Intermountain fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, or certain conditions result in an early termination date under any swap contract that is in excess of a specified amount, then Intermountain will be in default under the revolving credit agreement.

Centennial Energy Holdings, Inc. Centennial's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in Centennial's credit ratings have not limited, nor are currently expected to limit, Centennial's ability to access the capital markets. If Centennial were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding.

WBI Energy Transmission, Inc. WBI Energy Transmission has a $200.0 million uncommitted note purchase and private shelf agreement with an expiration date of May 16, 2019. WBI Energy Transmission had $100.0 million of notes outstanding at ~~March 31,~~September 30, 2017, which reduced the remaining capacity under this uncommitted private shelf agreement to $100.0 million.

Off balance sheet arrangements

As of ~~March 31,~~September 30, 2017, the Company had no material off balance sheet arrangements as defined by the rules of the SEC.

Contractual obligations and commercial commitments

There are no material changes in the Company's contractual obligations from continuing operations relating to long-term debt, estimated interest payments, operating leases, purchase commitments, asset retirement obligations, uncertain tax positions and minimum funding requirements for its defined benefit plans ~~for 2017~~ from those reported in the 2016 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2016 Annual Report.

New Accounting Standards

For information regarding new accounting standards, see Note 6, which is incorporated by reference.

Critical Accounting Policies Involving Significant Estimates

The Company's critical accounting policies involving significant estimates include impairment testing of assets held for sale, impairment testing of long-lived assets and intangibles, revenue recognition, pension and other postretirement benefits, and income taxes. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 2016 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2016 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to the impact of market fluctuations associated with interest rates. The Company has policies and procedures to assist in controlling these market risks and from time to time has utilized derivatives to manage a portion of its risk.

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the 2016 Annual Report.

At ~~March 31,~~September 30, 2017, the Company had no outstanding interest rate hedges.

Item 4. Controls and Procedures

The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.

Evaluation of disclosure controls and procedures

The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company's disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of the Company's disclosure controls and ~~procedures.~~procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and the chief financial officer have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.

Changes in internal controls

No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended ~~March 31,~~September 30, 2017, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

Part II -- Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings required by this item, see Note 16, which is incorporated herein by reference.

Item 1A. Risk Factors

There are no material changes to the Company's risk factors from those reported in Part I, Item 1A - Risk Factors in the 2016 Annual Report.

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~

~~The following table includes information with respect to the Company's purchase of equity securities:~~

~~ISSUER PURCHASES OF EQUITY SECURITIES~~

Period
(a)
Total Number
of Shares
(or Units)
Purchased (1)

(b)
Average Price Paid per Share
(or Unit)

(c)
Total Number of Shares
(or Units) Purchased
as Part of Publicly
Announced Plans
or Programs (2)
(d)
Maximum Number (or
Approximate Dollar
Value) of Shares (or
Units) that May Yet Be
Purchased Under the
Plans or Programs (2)
January 1 through January 31, 2017 —

February 1 through February 28, 2017 64,384

$26.15

March 1 through March 31, 2017 —

Total 64,384


~~(1)~~	~~Represents shares of common stock purchased on the open market in connection with the vesting of shares granted pursuant to the Long-Term Performance-Based Incentive Plan.~~


~~(2)~~	~~Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.~~

Item 4. Mine Safety Disclosures

For information regarding mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, see Exhibit 95 to this Form 10-Q, which is incorporated herein by reference.

Item 5. Other Information

None.

Item 6. Exhibits

See the index to exhibits immediately preceding the exhibits filed with this report.

Signatures

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



		MDU RESOURCES GROUP, INC.

DATE:	~~May 8,~~November 3, 2017	BY:	/s/ ~~Doran N. Schwartz~~Jason L. Vollmer
			~~Doran N. Schwartz~~Jason L. Vollmer
			Vice President, ~~and~~ Chief Financial Officer and Treasurer


		BY:	/s/ ~~Jason L. Vollmer~~Stephanie A. Barth
			~~Jason L. Vollmer~~Stephanie A. Barth
			Vice President, Chief Accounting Officer and ~~Treasurer~~ Controller

Exhibit Index



Exhibit No.

3 +10(a)		Bylaws of MDU Resources Group, Inc., as amended and restated on February 16, 2017, filed as Exhibit 3.1 to Form 8-K dated February 16, 2017, filed on February 21, 2017, in File No. 1-03480*

~~+10(a)~~		MDU Resources Group, Inc. 401(k) Retirement Plan, as restated as of January 1, 2017**

~~+10(b)~~		Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated ~~March 31,~~August 30, 2017**

+10(b)	MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of October 10, 2017**

+10(c)	~~+10(c)~~		~~Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 16,~~Jason L. Vollmer Offer Letter, dated September 20, 2017, filed as Exhibit 10.1 to Form 8-K dated ~~February 16,~~September 15, 2017, filed on ~~February~~September 21, 2017, in File No. 1-03480*

12	12		Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends**

31(a)	~~31(a)~~		Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**

31(b)	~~31(b)~~		Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**

32	32		Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

95	95		Mine Safety Disclosures**

101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

~~101~~101.SCH	XBRL Taxonomy Extension Schema Document

~~The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, formatted in~~ 101.CAL	XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.Taxonomy Extension Calculation Linkbase Document

* Incorporated herein by reference as indicated.

** Filed herewith.

101.DEFXBRL Taxonomy Extension Definition Linkbase Document101.LABXBRL Taxonomy Extension Label Linkbase Document101.PREXBRL Taxonomy Extension Presentation Linkbase Document* Incorporated herein by reference as indicated.** Filed herewith.+ Management contract, compensatory plan or arrangement.

MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

4446



Delaware		41-0423660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



Large accelerated filer ý	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o
	Emerging growth company o



Three Months Ended March 31, 2017	Balance at January 1, 2017		Goodwill Acquired During the Year		Balance at March 31, 2017
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736
Construction materials and contracting	176,290		—		176,290
Construction services	109,765		—		109,765
Total	$	631,791	$	—	$	631,791


*	The insurance contract invests approximately 50 percent in fixed-income investments, 23 percent in common stock of large-cap companies, 13 percent in common stock of mid-cap companies, 11 percent in common stock of small-cap companies, 2 percent in target date investments and 1 percent in cash equivalents.


*	Income taxes ~~refunded,~~paid (refunded), net of discontinued operations, were ~~$(7.2)~~$1.4 million and ~~$(1.4) million~~$(144,000) for the ~~three~~nine months ended ~~March 31,~~September 30, 2017 and 2016, respectively.



Period	(a) Total Number of Shares (or Units) Purchased (1)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
January 1 through January 31, 2017	—
February 1 through February 28, 2017	64,384		$26.15
March 1 through March 31, 2017	—
Total	64,384

September 30,

(In thousands)

Property, plant and equipment additions in accounts payable