UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~September 30, 2017~~March 31, 2018

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

For the transition period from _____________ to ______________

Commission file number 1-03480

MDU RESOURCES GROUP, INC.

(Exact name of registrant as specified in its charter)



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

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act (Check one):



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

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.

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of ~~October~~April 27, ~~2017:~~2018: 195,304,376 shares.

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~~--Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	6

	Consolidated Statements of Comprehensive Income -- ~~Three and Nine~~--Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	7

	Consolidated Balance Sheets -- ~~September 30,~~ March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016~~2017	8

	Consolidated Statements of ~~Cash Flows~~Equity -- ~~Nine~~ Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	9

	~~Notes to~~ Consolidated ~~Financial~~ Statements of Cash Flows --Three Months Ended March 31, 2018 and 2017	10

	Notes to Consolidated Financial Statements	11

Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations	3132

Item 3	Quantitative and Qualitative Disclosures About Market Risk	4446

Item 4	Controls and Procedures	4446

Part II -- Other Information

Item 1	Legal Proceedings	4447

Item 1A	Risk Factors	4447

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 4	Mine Safety Disclosures	4447

Item 5	Other Information	4447

Item 6	Exhibits	4447

~~Signatures~~		Exhibits Index	4548

~~Exhibit Index~~ Signatures		4649

~~Exhibits~~

Definitions

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



Abbreviation or Acronym
~~2016~~2017 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017
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~~IBEW	International ~~Financial Reporting Standards~~Brotherhood of Electrical Workers
ICWU	International Chemical Workers Union
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.
MMcf	Million cubic feet
MMdk	Million dk
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
MTPSC	Montana Public Service Commission
MW	Megawatt



MW	~~Megawatt~~
NDPSC	North Dakota Public Service Commission
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
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
SSIP	System Safety and Integrity Program
TCJA	Tax Cuts and Jobs Act
Tesoro	Tesoro Refining & Marketing Company LLC
~~Tesoro Logistics~~	~~QEP Field Services, LLC doing business as Tesoro Logistics Rockies LLC~~
VIE	Variable interest entity
Washington DOE	Washington State Department of Ecology
WBI Energy	WBI Energy, Inc., 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 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.~~Business Segment Financial and Operating Data.

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~~2017 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~~Note 13.

Part I -- Financial Information

Item 1. Financial Statements

MDU Resources Group, Inc.

Consolidated Statements of Income

(Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,												March 31,
	2017			2016			2017			2016			2018		2017
	(In thousands, except per share amounts)												(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream	$	206,936		$	192,079		$	866,035		$	783,997		$	424,459	$	433,614
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	1,065,612			1,016,488			2,412,077			2,328,733			551,834		504,311
Total operating revenues	1,272,548			1,208,567			3,278,112			3,112,730			976,293		937,925
Operating expenses:
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream	79,293			77,662			235,306			229,364			86,112		79,548
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	893,616			842,878			2,115,747			2,008,122			514,744		478,994
Total operation and maintenance	972,909			920,540			2,351,053			2,237,486			600,856		558,542
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			181,967		192,948
Depreciation, depletion and amortization	52,155			54,094			155,138			163,226			52,729		51,325
Taxes, other than income	38,882			36,128			127,273			116,864			48,854		47,438
Electric fuel and purchased power													22,511		21,886
Total operating expenses	1,116,171			1,061,883			2,974,944			2,815,096			906,917		872,139
Operating income	156,377			146,684			303,168			297,634			69,376		65,786
Other income	1,011			1,741			2,809			3,662			582		2,343
Interest expense	20,909			22,278			61,978			67,365			20,447		20,303
Income before income taxes	136,479			126,147			243,999			233,931			49,511		47,826
Income taxes	46,930			37,761			74,406			67,381			7,551		12,188
Income from continuing operations	89,549			88,386			169,593			166,550			41,960		35,638
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)	—			—			—			(131,691		)
Loss on redemption of preferred stocks	—			—			600			—
Income from discontinued operations, net of tax (Note 9)													477		1,687
Net income													42,437		37,325
Dividends declared on preferred stocks	—			171			171			514			—		171
Earnings (loss) on common stock	$	87,351		$	82,815		$	165,120		$	(1,811	)
Earnings (loss) per common share - basic:
Earnings on common stock													$	42,437	$	37,154
Earnings per common share - basic:
Earnings before discontinued operations	$	.46		$	.45		$	.86		$	.85		$	.22	$	.18
Discontinued operations attributable to the Company, net of tax	(.01		)	(.03		)	(.01		)	(.86		)
Earnings (loss) per common share - basic	$	.45		$	.42		$	.85		$	(.01	)
Earnings (loss) per common share - diluted:
Discontinued operations, net of tax													—		.01
Earnings per common share - basic													$	.22	$	.19
Earnings per common share - diluted:
Earnings before discontinued operations	$	.46		$	.45		$	.86		$	.85		$	.22	$	.18
Discontinued operations attributable to the Company, net of tax	(.01		)	(.03		)	(.02		)	(.86		)
Earnings (loss) per common share - diluted	$	.45		$	.42		$	.84		$	(.01	)
Discontinued operations, net of tax													—		.01
Earnings per common share - diluted													$	.22	$	.19
Dividends declared per common share	$	.1925		$	.1875		$	.5775		$	.5625		$	.1975	$	.1925
Weighted average common shares outstanding - basic	195,304			195,304			195,304			195,298			195,304		195,304
Weighted average common shares outstanding - diluted	195,783			195,811			195,922			195,794			195,982		196,023

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 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 )



	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
Net income	$	42,437		$	37,325
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $56 and $56 for the three months ended in 2018 and 2017, respectively	92			91
Postretirement liability adjustment:
Amortization of postretirement liability losses included in net periodic benefit cost (credit), net of tax of $155 and $217 for the three months ended in 2018 and 2017, respectively	418			357
Reclassification of postretirement liability adjustment from regulatory asset, net of tax of $0 and $(725) for the three months ended in 2018 and 2017, respectively	—			(917		)
Postretirement liability adjustment	418			(560		)
Foreign currency translation adjustment recognized during the period, net of tax of $(1) and $5 for the three months ended in 2018 and 2017, respectively	(2		)	9
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 $(28) and $(15) for the three months ended in 2018 and 2017, respectively	(105		)	(27		)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $7 and $19 for the three months ended in 2018 and 2017, respectively	30			35
Net unrealized gain (loss) on available-for-sale investments	(75		)	8
Other comprehensive income (loss)	433			(452		)
Comprehensive income attributable to common stockholders	$	42,870		$	36,873

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

MDU Resources Group, Inc.

Consolidated Balance Sheets

(Unaudited)


	September 30, 2017			September 30, 2016			December 31, 2016			March 31, 2018			March 31, 2017			December 31, 2017
(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	$	37,356		$	59,868		$	46,107		$	58,764		$	50,735		$	34,599
Receivables, net	739,402			665,142			630,243			664,319			554,185			727,030
Inventories	232,555			245,790			238,273			257,792			250,609			226,583
Prepayments and other current assets	89,625			49,082			48,461			59,481			79,254			81,304
Current assets held for sale	304			45,867			14,391			458			7,290			479
Total current assets	1,099,242			1,065,749			977,475			1,040,814			942,073			1,069,995
Investments	133,895			126,048			125,866			138,451			129,009			137,613
Property, plant and equipment	6,658,891			6,588,445			6,510,229			6,842,967			6,544,077			6,770,829
Less accumulated depreciation, depletion and amortization	2,667,762			2,583,566			2,578,902			2,725,484			2,609,303			2,691,641
Net property, plant and equipment	3,991,129			4,004,879			3,931,327			4,117,483			3,934,774			4,079,188
Deferred charges and other assets:
Goodwill	631,791			641,527			631,791			631,791			631,791			631,791
Other intangible assets, net	4,209			6,529			5,925			3,465			5,347			3,837
Other	419,846			360,537			415,419			412,456			409,745			407,850
Noncurrent assets held for sale	64,333			112,440			196,664			4,392			95,719			4,392
Total deferred charges and other assets	1,120,179			1,121,033			1,249,799			1,052,104			1,142,602			1,047,870
Total assets	$	6,344,445		$	6,317,709		$	6,284,467		$	6,348,852		$	6,148,458		$	6,334,666
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year	$	148,499		$	93,598		$	43,598		$	149,199		$	43,499		$	148,499
Accounts payable	304,101			281,373			279,962			267,994			239,013			312,327
Taxes payable	108,946			59,747			48,164			57,354			74,638			42,537
Dividends payable	37,596			36,791			37,767			38,573			37,767			38,573
Accrued compensation	67,097			58,604			65,867			35,087			32,350			72,919
Other accrued liabilities	184,580			191,904			184,377			204,328			188,373			186,010
Current liabilities held for sale	5,749			18,065			9,924			11,726			2,394			11,993
Total current liabilities	856,568			740,082			669,659			764,261			618,034			812,858
Long-term debt	1,592,053			1,808,350			1,746,561			1,630,343			1,659,507			1,566,354
Deferred credits and other liabilities:
Deferred income taxes	652,413			662,326			668,226			346,218			666,905			347,271
Other	889,494			821,890			883,777			1,181,919			890,107			1,179,140
Total deferred credits and other liabilities	1,541,907			1,484,216			1,552,003			1,528,137			1,557,012			1,526,411
Commitments and contingencies
Stockholders' equity:
Preferred stocks	—			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 September 30, 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 March 31, 2018 and 2017 and December 31, 2017										195,843			195,843			195,843
Other paid-in capital	1,232,766			1,231,396			1,232,478			1,227,285			1,231,171			1,233,412
Retained earnings	964,275			884,339			912,282			1,051,469			911,702			1,040,748
Accumulated other comprehensive loss	(35,341		)	(37,891		)	(35,733		)	(44,860		)	(36,185		)	(37,334		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,353,917			2,270,061			2,301,244			2,426,111			2,298,905			2,429,043
Total stockholders' equity	2,353,917			2,285,061			2,316,244			2,426,111			2,313,905			2,429,043
Total liabilities and stockholders' equity	$	6,344,445		$	6,317,709		$	6,284,467		$	6,348,852		$	6,148,458		$	6,334,666

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

MDU Resources Group, Inc.

Consolidated Statements of Equity

(Unaudited)



Three Months Ended March 31, 2018
				Other Paid-in Capital			Retained Earnings			Accumu-lated Other Compre-hensive Loss
	Common Stock												Treasury Stock
	Shares	Amount											Shares		Amount			Total

Balance at December 31, 2017	195,843,297	$	195,843	$	1,233,412		$	1,040,748		$	(37,334	)	(538,921	)	$	(3,626	)	$	2,429,043
Cumulative effect of adoption of ASU 2014-09	—	—		—			(970		)	—			—		—			(970		)
Adjusted balance at January 1, 2018	195,843,297	195,843		1,233,412			1,039,778			(37,334		)	(538,921	)	(3,626		)	2,428,073
Net income	—	—		—			42,437			—			—		—			42,437
Other comprehensive income	—	—		—			—			433			—		—			433
Reclassification of certain prior period tax effects from accumulated other comprehensive loss	—	—		—			7,959			(7,959		)	—		—			—
Dividends declared on common stock	—	—		—			(38,572		)	—			—		—			(38,572		)
Stock-based compensation	—	—		1,223			(133		)	—			—		—			1,090
Repurchase of common stock	—	—		—			—			—			(182,424	)	(5,020		)	(5,020		)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	—	—		(7,350		)	—			—			182,424		5,020			(2,330		)
Balance at March 31, 2018	195,843,297	$	195,843	$	1,227,285		$	1,051,469		$	(44,860	)	(538,921	)	$	(3,626	)	$	2,426,111



Three Months Ended March 31, 2017
							Other Paid-in Capital			Retained Earnings			Accumu-lated Other Compre-hensive Loss
	Preferred Stock			Common Stock												Treasury Stock
	Shares	Amount		Shares	Amount											Shares		Amount			Total

Balance at December 31, 2016	150,000	$	15,000	195,843,297	$	195,843	$	1,232,478		$	912,282		$	(35,733	)	(538,921	)	$	(3,626	)	$	2,316,244
Net income	—	—		—	—		—			37,325			—			—		—			37,325
Other comprehensive loss	—	—		—	—		—			—			(452		)	—		—			(452		)
Dividends declared on preferred stocks	—	—		—	—		—			(171		)	—			—		—			(171		)
Dividends declared on common stock	—	—		—	—		—			(37,596		)	—			—		—			(37,596		)
Stock-based compensation	—	—		—	—		1,134			(138		)	—			—		—			996
Repurchase of common stock	—	—		—	—		—			—			—			(64,384	)	(1,684		)	(1,684		)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	—	—		—	—		(2,441		)	—			—			64,384		1,684			(757		)
Balance at March 31, 2017	150,000	$	15,000	195,843,297	$	195,843	$	1,231,171		$	911,702		$	(36,185	)	(538,921	)	$	(3,626	)	$	2,313,905

MDU Resources Group, Inc.

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2017			2016			2018			2017
	(In thousands)						(In thousands)
Operating activities:
Net income (loss)	$	165,891		$	(132,988	)
Loss from discontinued operations, net of tax	(3,702		)	(299,538		)
Net income							$	42,437		$	37,325
Income from discontinued operations, net of tax							477			1,687
Income from continuing operations	169,593			166,550			41,960			35,638
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	155,138			163,226			52,729			51,325
Deferred income taxes	(16,777		)	(1,346		)	(2,068		)	(332		)
Changes in current assets and liabilities, net of acquisitions:
Receivables	(121,128		)	(75,308		)	62,711			63,684
Inventories	2,047			(4,153		)	(29,997		)	(13,676		)
Other current assets	(40,655		)	(18,824		)	22,506			(31,006		)
Accounts payable	30,097			15,514			(31,864		)	(23,380		)
Other current liabilities	66,647			48,973			(5,115		)	(1,179		)
Other noncurrent changes	(15,081		)	(25,284		)	(5,302		)	2,161
Net cash provided by continuing operations	229,881			269,348			105,560			83,235
Net cash provided by discontinued operations	42,020			7,127			231			3,304
Net cash provided by operating activities	271,901			276,475			105,791			86,539
Investing activities:
Capital expenditures	(222,084		)	(303,873		)	(105,136		)	(72,316		)
Net proceeds from sale or disposition of property and other	121,162			17,583			5,966			117,967
Investments	(260		)	56			(1,074		)	(116		)
Net cash used in continuing operations	(101,182		)	(286,234		)
Net cash provided by (used in) continuing operations							(100,244		)	45,535
Net cash provided by discontinued operations	2,234			31,918			—			54
Net cash used in investing activities	(98,948		)	(254,316		)
Net cash provided by (used in) investing activities							(100,244		)	45,589
Financing activities:
Issuance of long-term debt	133,437			341,777			101,588			59,985
Repayment of long-term debt	(183,968		)	(236,433		)	(37,047		)	(147,277		)
Dividends paid	(113,131		)	(110,366		)	(38,573		)	(37,767		)
Redemption of preferred stock	(15,600		)	—
Repurchase of common stock	(1,684		)	—			(5,020		)	(1,684		)
Tax withholding on stock-based compensation	(757		)	(323		)	(2,330		)	(757		)
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		)	3
Decrease in cash and cash equivalents	(8,751		)	(24,035		)
Net cash provided by (used in) continuing operations							18,618			(127,500		)
Net cash provided by discontinued operations							—			—
Net cash provided by (used in) financing activities							18,618			(127,500		)
Increase in cash and cash equivalents							24,165			4,628
Cash and cash equivalents -- beginning of year	46,107			83,903			34,599			46,107
Cash and cash equivalents -- end of period	$	37,356		$	59,868		$	58,764		$	50,735

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

MDU Resources Group, Inc.

Notes to Consolidated

Financial Statements

~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~

(Unaudited)

Note 1 - Basis of presentation

The accompanying consolidated interim financial statements were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of 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~~2017 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 ~~September 30, 2017,~~March 31, 2018, up to the date of issuance of these consolidated interim financial statements.

On December 22, 2017, President Trump signed into law the TCJA which includes lower corporate tax rates, repealing the domestic production deduction, disallowance of immediate expensing for regulated utility property and modifying or repealing many other business deductions and credits. The reduction in the corporate tax rate was effective on January 1, 2018, which resulted in lower income tax expense for the three months ended March 31, 2018. The Company continues to review the components of the TCJA and the impact on the Company's consolidated financial statements and related disclosures for 2018 and thereafter.

While the Company was able to make reasonable estimates of the impact of the reduction in corporate tax rate on the Company's net deferred tax liabilities during the fourth quarter of 2017, it may be affected by other analyses related to the TCJA, including, but not limited to, the state tax effect of adjustments to federal temporary differences and the calculation of deemed repatriation of deferred foreign income. The final transition impacts of the TCJA may differ from amounts disclosed, possibly materially, due to, among other things, interpretations, legislative action to address questions, changes in accounting standards for income taxes or related interpretations, or updates or changes to estimates the Company has utilized to calculate the transition impacts. The SEC has issued rules that would allow for a measurement period of up to one year after the enactment date of the TCJA to finalize the recording of the related tax impacts, of which there were no such adjustments in the first quarter of 2018. The Company currently anticipates finalizing and recording any resulting adjustments by December 31, 2018, which will be included in income from continuing operations.

Due to the enactment of the TCJA, the regulated jurisdictions in which the Company's regulated businesses provides service have requested the Company furnish plans for the effect of the reduced corporate tax rate, which may impact the Company's tax rates. Therefore, the Company has reserved for such impacts as an offset to revenue in certain jurisdictions. The Company will continue to make changes to reserve balances as required. For more information on the details of each jurisdiction's request, see Note 15.

Effective January 1, 2018, the Company adopted the requirements of the revenue from contracts with customers guidance following the modified retrospective method, as discussed in Notes 6 and 8. As such, results for reporting periods beginning January 1, 2018, are presented under the new guidance, while prior period amounts are not adjusted and continue to be reported in accordance with the historic accounting for revenue recognition. Based on the Company's analysis, the Company did not identify a significant change in the timing of revenue recognition under the new guidance as compared to the historic accounting for revenue recognition.

Certain prior year amounts have been reclassified to conform to the current year presentation in the consolidated financial statements related to the retrospective adoption of the FASB guidance to improve the presentation of net periodic pension and net periodic postretirement benefit costs, which was effective on January 1, 2018. The components of net periodic pension and postretirement costs, other than service costs, were reclassified from operating expenses to other income on the Consolidated Statements of Income, as discussed in Note 6.

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 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. 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 8.9.

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 ~~$27.2~~$36.3 million, $26.3 million and ~~$29.2~~$34.7 million at ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, 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 ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, was ~~$9.0~~$8.2 million, ~~$10.2~~$10.9 million and ~~$10.5~~$8.1 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 iswas included in inventories. Inventories ~~consisted of:~~on the Company's Consolidated Balance Sheets were as follows:


	September 30, 2017		September 30, 2016		December 31, 2016		March 31, 2018		March 31, 2017		December 31, 2017
	(In thousands)						(In thousands)
Aggregates held for resale	$	116,399	$	119,078	$	115,471	$	123,053	$	120,392	$	115,268
Natural gas in storage (current)	29,974		35,625		25,761
Asphalt oil	26,682		23,480		29,103		61,647		50,538		30,360
Materials and supplies	20,778		18,584		18,372		19,493		22,074		18,650
Merchandise for resale	15,346		15,672		16,437		16,378		16,546		14,905
Natural gas in storage (current)							10,936		11,282		20,950
Other	23,376		33,351		33,129		26,285		29,777		26,450
Total	$	232,555	$	245,790	$	238,273	$	257,792	$	250,609	$	226,583

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 $47.8 million, $49.5 million ~~$49.1 million~~ and ~~$49.5~~$49.3 million at ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, 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~~nonvested performance share ~~awards.~~awards and restricted stock units. Common stock outstanding includes issued shares less shares held in treasury. ~~Net income (loss)~~Earnings on common stock 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		Three Months Ended
	September 30,				March 31,
	2017	2016	2017	2016	2018	2017
	(In thousands)				(In thousands)
Weighted average common shares outstanding - basic	195,304	195,304	195,304	195,298	195,304	195,304
Effect of dilutive performance share awards	479	507	618	496	678	719
Weighted average common shares outstanding - diluted	195,783	195,811	195,922	195,794	195,982	196,023
Shares excluded from the calculation of diluted earnings per share	—	—	—	—	—	—

Note 6 - New accounting standards

Recently adopted accounting standards

~~Balance Sheet Classification of Deferred Taxes~~ In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. The guidance requires all deferred tax assets and liabilities to be classified as noncurrent. These amendments align GAAP with IFRS. The Company adopted the guidance in the fourth quarter 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's results of operations 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 assetsASU 2014-09 - ~~deferred income taxes to deferred credits and 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 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 in the first quarter of 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 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 deferring the effective date of the revenue guidance and allowing entities to

early adopt. With this decision, the guidance ~~will be~~was effective for the Company on January 1, 2018. Entities ~~will have~~had 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~~recognizes 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 adopted the guidance on January 1, 2018, using the modified retrospective approach. The Company elected the practical expedient to not disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, along with an explanation of when such revenue would be expected to be recognized. This practical expedient was used since the performance obligations are part of contracts with an original duration of one year or less. The Company also elected the practical expedient to recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that the Company ~~has~~otherwise would have recognized is one year or less. Upon completion of the Company's evaluation of contracts and methods of revenue recognition under the previous accounting guidance, the Company did not ~~identified~~identify any material cumulative effect adjustments to be made to retained earnings. In addition, the ~~guidance will require~~Company has expanded revenue disclosures, both ~~quantitative~~quantitatively and ~~qualitative,~~qualitatively, related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with ~~customers. To date, the~~customers, as discussed in Note 8. The Company has reviewed ~~nearly all of~~ its revenue streams ~~completing the~~

~~preliminary evaluation of~~to evaluate the impact of this ~~guidance. Based on the preliminary evaluation, the Company does~~guidance and did not ~~anticipate~~identify a significant change in the timing of revenue recognition, results of operations, financial position or cash ~~flows, however~~flows. The Company reviewed its internal controls related to revenue recognition and disclosures and concluded that the guidance impacts certain business processes and controls. As such, the Company ~~will~~has developed modifications to its internal controls for certain topics under the guidance as they apply to the Company and such modifications were not deemed to be significant. Results for reporting periods beginning after December 31, 2017, are presented under the new guidance, while prior period amounts are not adjusted and continue to ~~evaluate~~be reported in accordance with historic accounting for revenue recognition.

Under the ~~impact of this guidance through the date of 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, the guidance was applied only to contracts that were not completed as of January 1, 2018. Therefore, the Company recognized the cumulative effect of initially applying the guidance with an adjustment to the ~~exception~~opening balance of ~~equity securities without readily determinable fair values which will be applied prospectively.~~retained earnings at January 1, 2018. In the first quarter of 2018, there was not a material impact to the financial statements as a result of applying the guidance. The ~~Company is evaluating the effects the adoption~~cumulative effect of the ~~new guidance will have on its results of operations, financial position, cash flows~~changes made to the Consolidated Balance Sheet was as follows:



	December 31, 2017		Adjustments			January 1, 2018
	(In thousands)
Liabilities and Stockholders' Equity
Current liabilities:
Other accrued liabilities	$	186,010	$	903		$	186,913
Deferred credits and other liabilities:
Deferred income taxes	347,271		(332		)	346,939
Other	1,179,140		399			1,179,539
Commitments and contingencies
Stockholders' equity:
Common stockholders' equity:
Retained earnings	1,040,748		(970		)	1,039,778

The cumulative adjustment is related to prepaid natural gas transportation to storage contracts where a separate performance obligation existed and ~~disclosures.~~has not yet been satisfied. As such, these contracts were still open and met the criteria for a cumulative effect adjustment.

ASU 2016-15 - 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. 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 ~~plans to adopt~~adopted the guidance on January 1, ~~2018.~~2018, on a prospective basis. The ~~Company's initial evaluation of the~~ guidance did not ~~identify any changes to~~have a material effect on the ~~current presentation of the~~Company's statement of cash ~~flows; therefore, no retrospective adjustments to prior periods will be necessary.~~flows.

ASU 2017-01 - 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~~Company adopted the ~~Company~~guidance 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~~basis. The guidance did not ~~been reported in the financial statements or made available for issuance. The Company expects to adopt this guidance as required and does not expect the guidance to~~ have a material effect on ~~its~~the Company's results of operations, financial position, cash flows ~~and~~or disclosures.

ASU 2017-07 - 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.~~costs. 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 periodic 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~~Company adopted the ~~Company~~guidance 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.~~

basis. 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 Company's Consolidated Statements of ~~Income. The~~Income with no impact ~~upon adoption~~to earnings. As a result of the ~~new~~retrospective application of this change in accounting guidance, ~~will be an increase to operating income~~the Company reclassified $1.8 million from operation and ~~decrease~~maintenance expense to other income on the Consolidated Statements of Income for the three months ended March 31, 2017. The Company also reclassified unrealized gains on investments used to satisfy obligations under the defined benefit plans of $3.1 million for the three months ended March 31, 2017, which were included in operation and ~~no impact~~maintenance expense, to ~~earnings.~~other income on the Consolidated Statements of Income. The guidance ~~will~~did not have a material ~~impact~~effect on the Company's ~~disclosures~~results of operations, cash flows or ~~cash flows.~~disclosures.

ASU 2018-02 - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued guidance that allows an entity to reclassify the stranded tax effects resulting from the newly enacted federal corporate income tax rate from accumulated other comprehensive income (loss) to retained earnings. The guidance is effective for the Company on January 1, 2019, including interim periods, with early adoption permitted. The guidance can be applied using one of two methods. One method is to record the reclassification of the stranded income taxes at the beginning of the period of adoption. The other method is to apply the guidance retrospectively to each period in which the income tax effects of the TCJA are recognized in accumulated other comprehensive income (loss). The Company early adopted the guidance on January 1, 2018, and elected to reclassify the stranded income taxes at the beginning of the period. During the first quarter of 2018, the Company reclassified $7.9 million of stranded tax expense from accumulated other comprehensive loss to retained earnings. The guidance did not have a material effect on the Company's results of operations, cash flows or disclosures.

Recently issued accounting standards not yet adopted

ASU 2016-02 - 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.

In January 2018, the FASB issued a practical expedient for land easements under the new lease guidance. The practical expedient permits an entity to elect the option to not evaluate land easements under the new guidance if they existed or expired before the adoption of the new lease guidance and were not previously accounted for as leases under the previous lease guidance. Once an entity adopts the new guidance, the entity should apply the new guidance on a prospective basis to all new or modified land easements. The Company is currently evaluating the impact of the practical expedient.

In January 2018, the FASB issued a proposed accounting standard update to the guidance that would allow an entity the option to adopt the guidance on a modified retrospective basis. Under the modified retrospective approach, an entity would recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. The Company is monitoring the status of the proposal.

ASU 2017-04 - 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 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
Three Months Ended March 31, 2018																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	$	(2,117	)	$	(33,469	)	$	(155	)	$	(48	)	$	(35,789	)	$	(1,934	)	$	(35,163	)	$	(155	)	$	(82	)	$	(37,334	)
Other comprehensive income (loss) before reclassifications	—			—			15			(19		)	(4		)
Other comprehensive loss before reclassifications																—			—			(2		)	(105		)	(107		)
Amounts reclassified from accumulated other comprehensive loss	92			333			—			27			452			92			418			—			30			540
Net current-period other comprehensive income	92			333			15			8			448
Net current-period other comprehensive income (loss)																92			418			(2		)	(75		)	433
Reclassification adjustment of prior period tax effects related to TCJA included in accumulated other comprehensive loss																(389		)	(7,520		)	(33		)	(17		)	(7,959		)
Balance at end of period	$	(2,025	)	$	(33,136	)	$	(140	)	$	(40	)	$	(35,341	)	$	(2,231	)	$	(42,265	)	$	(190	)	$	(174	)	$	(44,860	)



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
	(In thousands)
Balance at beginning of period	$	(2,300	)	$	(33,221	)	$	(149	)	$	(63	)	$	(35,733	)
Other comprehensive income (loss) before reclassifications	—			—			9			(27		)	(18		)
Amounts reclassified from accumulated other comprehensive loss	91			357			—			35			483
Amounts reclassified to accumulated other comprehensive loss from regulatory asset	—			(917		)	—			—			(917		)
Net current-period other comprehensive income (loss)	91			(560		)	9			8			(452		)
Balance at end of period	$	(2,209	)	$	(33,781	)	$	(140	)	$	(55	)	$	(36,185	)

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)
Balance at beginning of period $ (2,484 ) $ (35,604 ) $ (144 ) $ 26
$ (38,206 )
Other comprehensive loss before reclassifications —
—
(4 ) (42 ) (46 )
Amounts reclassified from accumulated other comprehensive loss 92
236
—
33
361
Net current-period other comprehensive income (loss) 92
236
(4 ) (9 ) 315
Balance at end of period $ (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,
	2018			2017
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income	$	(148	)	$	(147	)	Interest expense
	56			56			Income taxes
	(92		)	(91		)
Amortization of postretirement liability losses included in net periodic benefit cost (credit)	(573		)	(574		)	Other income
	155			217			Income taxes
	(418		)	(357		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(37		)	(54		)	Other income
	7			19			Income taxes
	(30		)	(35		)
Total reclassifications	$	(540	)	$	(483	)

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~~Note 8 - Revenue from contracts with customers

Revenue is recognized when a performance obligation is satisfied by transferring control over a product or service to a customer. Revenue is measured based on consideration specified in a contract with a customer, and excludes any sales incentives and amounts collected on behalf of third parties. The Company is considered an agent for certain taxes collected from customers. As such, the Company presents revenues net ~~periodic benefit cost (credit)~~of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.

The electric and natural gas distribution segments generate revenue from the sales of electric and natural gas products and services, which includes retail and transportation services. These segments establish a customer's retail or transportation service account based on the customer's application/contract for service, which indicates approval of a contract for service. The contract identifies an obligation to provide service in exchange for delivering or standing ready to deliver the identified commodity; and the customer is obligated to pay for the service as provided in the applicable tariff. The product sales are based on a fixed rate that includes a base and per-unit rate, which are included in approved tariffs as determined by state or federal regulatory agencies. The quantity of the commodity consumed or transported determines the total per-unit revenue. The service provided, along with the product consumed or transported, are a single performance obligation because both are required in combination to successfully transfer the contracted product or service to the customer. Revenues are recognized over time as customers receive and consume the products and services. The method of measuring progress toward the completion of the single performance obligation is on a per-unit output method basis, with revenue recognized based on the direct measurement of the value to the customer of the goods or services transferred to date. For contracts governed by the Company’s utility revenue tariffs, amounts are billed monthly with the amount due between 15 and 22 days of receipt of the invoice depending on the applicable state’s tariff. For other contracts not governed by tariff, payment terms are net thirty days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.

The pipeline and midstream segment generates revenue from providing natural gas transportation, gathering and underground storage services as well as other energy-related services to both third parties and internal customers, largely the natural gas distribution segment. The pipeline and midstream segment establishes a contract with a customer based upon the customer’s request for firm or interruptible natural gas transportation, storage or gathering service(s). The contract identifies an obligation for the segment to provide the requested service(s) in exchange for consideration from the customer over a specified term. Depending on the type of service(s) requested and contracted, the service provided may include transporting, gathering or storing an identified quantity of natural gas and/or standing ready to deliver or store an identified quantity of natural gas. Natural gas transportation, gathering and storage revenues are based on fixed rates, which may include reservation fees and/or per-unit commodity rates. The services provided by the segment are generally treated as single performance obligations satisfied over time simultaneous to when the service is provided and revenue is recognized. Rates for the segment’s regulated services are based on its FERC approved tariff or customer negotiated rates on special projects, and rates for its non-regulated services are negotiated with its customers and set forth in the contract. For contracts governed by the company’s tariff, amounts are billed on or before the ninth business day of the following month and the amount is due within twelve days of receipt of the invoice. For gathering contracts not governed by the tariff, amounts are due within twenty days of invoice receipt. For other contracts not governed by the tariff, payment terms are net thirty days. At this time, the segment has no material obligations for returns, refunds or other similar obligations.

The construction materials and contracting segment generates revenue from contracting services and construction materials sales. This segment focuses on the vertical integration of its contracting services with its construction materials to support the aggregate based product lines. This segment provides contracting services to a customer when a contract has been signed by both the customer and a representative of the segment obligating a service to be provided in exchange for the consideration identified in the contract. The nature of the services this segment provides generally includes integrating a set of services and related construction materials into a single project to create a distinct bundle of goods and services, which the Company evaluated and determined to be single performance obligations. The transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable consideration that exist in this segment's contracts include liquidated damages; performance bonuses or incentives and penalties; and index pricing. The variable amounts usually arise upon achievement of certain performance metrics. The Company estimates variable consideration at the most likely amount expected. Revenue is recognized over time using the input method based on the measurement of progress on a project. The input method is the preferred method of measuring revenue because the costs incurred have been determined to represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. This segment also sells construction materials to third parties and internal customers. The contract for material sales is the use of a sales order or an invoice, which includes the pricing and payment terms. All material contracts contain a single performance obligation for the delivery of a single distinct product or a distinct separately identifiable bundle of products and services. Revenue is recognized at a point in time when the performance obligation has been satisfied with the delivery of the products or services. The warranties associated with the sales are those consistent with a standard warranty that the product meets certain specifications for quality or those required by law. For most contracts, amounts billed to customers are due within thirty days of receipt. There are no material obligations for returns, refunds or other similar obligations.

The construction services segment generates revenue from specialty contracting services which also includes the sale of construction equipment and other supplies. This segment provides specialty contracting services to a customer when a contract has been signed by both the customer and a representative of the segment obligating a service to be provided in exchange for the

consideration identified in the contract. The nature of the services this segment provides generally includes multiple promised goods and services in a single project to create a distinct bundle of goods and services, which the Company evaluates to determine whether a separate performance obligation exists. The transaction price is the original contract price plus any subsequent change orders and variable consideration. Examples of variable consideration that exist in this segment's contracts include bonuses, incentives, penalties and liquidated damages. The variable amounts usually arise upon achievement of certain performance metrics. The Company estimates variable consideration at the most likely amount expected. Revenue is recognized over time using the input method based on the measurement of progress on a project. The input method is the preferred method of measuring revenue because the costs incurred have been determined to represent the best indication of the overall progress toward the transfer of such goods or services promised to a customer. This segment also sells construction equipment and other supplies to third parties and internal customers. The contract for these sales is the use of a sales order or invoice, which includes the pricing and payment terms. All such contracts include a single performance obligation for the delivery of a single distinct product or a distinct separately identifiable bundle of products and services. Revenue is recognized at a point in time when the performance obligation has been satisfied with the delivery of the products or services. The warranties associated with the sales are those consistent with a standard warranty that the product meets certain specifications for quality or those required by law. For most contracts, amounts billed to customers are due within thirty days of receipt. There are no material obligations for returns, refunds or other similar obligations.

The Company recognizes all other revenues when services are rendered or goods are delivered.

Disaggregation

In the following table, revenue is disaggregated by the type of customer or service provided. The Company believes this level of disaggregation best depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. The table also includes a reconciliation of the disaggregated revenue by reportable segments. For more information on the Company's business segments, see Note ~~14.~~13.



Three Months Ended March 31, 2018	Electric			Natural gas distribution			Pipeline and midstream			Construction materials and contracting			Construction services			Other			Total
	(in thousands)
Residential utility sales	$	35,183		$	192,886		$	—		$	—		$	—		$	—		$	228,069
Commercial utility sales	34,701			116,891			—			—			—			—			151,592
Industrial utility sales	8,770			7,809			—			—			—			—			16,579
Other utility sales	1,836			—			—			—			—			—			1,836
Natural gas transportation	—			11,179			21,818			—			—			—			32,997
Natural gas gathering	—			—			2,270			—			—			—			2,270
Natural gas storage	—			—			3,134			—			—			—			3,134
Contracting services	—			—			—			74,064			—			—			74,064
Construction materials	—			—			—			173,591			—			—			173,591
Intrasegment eliminations*	—			—			—			(34,270		)	—			—			(34,270		)
Inside specialty contracting	—			—			—			—			233,821			—			233,821
Outside specialty contracting	—			—			—			—			87,181			—			87,181
Other	8,252			3,999			3,326			—			(86		)	2,696			18,187
Intersegment eliminations	—			—			(21,759		)	(101		)	(11		)	(2,638		)	(24,509		)
Revenues from contracts with customers	88,742			332,764			8,789			213,284			320,905			58			964,542
Revenues out of scope	(1,338		)	(100		)	44			—			13,145			—			11,751
Total external operating revenues	$	87,404		$	332,664		$	8,833		$	213,284		$	334,050		$	58		$	976,293


*	Intrasegment revenues are presented within the construction materials and contracting segment to highlight the focus on vertical integration as this segment sells materials to both third parties and internal customers. Due to consolidation requirements, these revenues must be eliminated against construction materials to arrive at the external operating revenue total for the segment.

~~Note 8 - Assets held for sale and discontinued operations~~

~~Assets held for sale~~Contract balances

The timing of revenue recognition may differ from the timing of invoicing to customers. Contracts from contracting services are billed as work progresses in accordance with agreed upon contractual terms. Generally, billing to the customer occurs contemporaneous to revenue recognition. A variance in timing of the billings may result in a contract asset or a contract liability. A contract asset occurs when revenues are recognized under the cost-to-cost measure of progress, which exceeds amounts billed on uncompleted contracts. Such amounts will be billed as standard contract terms allow, usually based on various measures of performance or achievement. A contract liability occurs when there are billings in excess of revenues recognized under the cost-to-cost measure of progress on uncompleted contracts. Contract liabilities decrease as revenue is recognized from the satisfaction of the related performance obligation. The change in contract 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.~~

~~Pronghorn~~On 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



	March 31, 2018			December 31, 2017			Change			Location on Consolidated Balance Sheets
	(In thousands)
Contract assets	$	132,610		$	122,184		$	10,426		Receivables, net
Contract liabilities - current	(80,905		)	(71,479		)	(9,426		)	Accounts payable
Contract liabilities - noncurrent	(399		)	—			(399		)	Deferred credits and other liabilities - other
Net contract assets (liabilities)	$	51,306		$	50,705		$	601

At March 31, 2018, the Company's net contract assets increased $601,000 compared to December 31, 2017. Included in the change of total contract assets (liabilities) was an increase in contract assets, due to revenue recognized in excess of billings on contracts, and an increase in contract liabilities, due to billings on contracts in excess of revenues recognized. The Company recognized $52.0 million in revenue for the three months ended March 31, 2018, which was previously included in contract liabilities at December 31, 2017. The Company recognized $3.1 million in revenue for the three months ended March 31, 2018, from performance obligations satisfied in prior periods.

Note 9 - 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 ~~loss~~income 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. At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded.

Dakota Prairie Refining 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. 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~~reduced 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		March 31, 2018			March 31, 2017		December 31, 2017
	(In thousands)							(In thousands)
Assets
Current assets:
Receivables, net	$	—		$	13	$	—
Income taxes receivable	8,444		(a)	32,388		13,987		$	1,858	(a)	$	11,756	$	1,778	(a)
Prepayments and other current assets	—			7,741		—
Total current assets held for sale	8,444			40,142		13,987		1,858			11,756		1,778
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	$	1,858		$	11,756	$	1,778
Liabilities
Current liabilities:
Accounts payable	$	—		$	7,063	$	7,425	$	—		$	16	$	—
Other accrued liabilities	—			7,743		—
Total current liabilities held for sale	—			14,806		7,425		—			16		—
Noncurrent liabilities:
Deferred income taxes (b)	55			—		14		37			55		37
Total noncurrent liabilities held for sale	55			—		14		37			55		37
Total liabilities held for sale	$	55		$	14,806	$	7,439	$	37		$	71	$	37


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


(b)	On the Company's Consolidated Balance Sheets, these amounts were reclassified to ~~noncurrent~~deferred charges and other assets - deferred income ~~tax~~taxes and are reflected in noncurrent assets ~~and are~~held for sale.

~~reflected in noncurrent assets held for sale.~~

The Company retained certain liabilities of Dakota Prairie Refining.In the first quarter of 2017, the Company recorded a reversal of athe previously accrued liability of $7.0 million ($4.3 million after tax) due to the resolution of a legal matter. ~~At September 30, 2017,~~As of March 31, 2018, Dakota Prairie Refining ~~had not~~ incurred ~~any~~no 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.

Fidelity In 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 substantially 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			March 31, 2018		March 31, 2017			December 31, 2017
	(In thousands)								(In thousands)
Assets
Current assets:
Receivables, net	$	304	$	7,930		$	355		$	458	$	266		$	479
Total current assets held for sale	304		7,930			355			458		266			479
Noncurrent assets:
Net property, plant and equipment	2,064		5,507			5,507			1,631		4,515			1,631
Deferred income taxes	62,163		104,726			91,098			2,637		91,098			2,637
Other	161		161			161			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			4,429		95,774			4,429
Total assets held for sale	$	64,692	$	117,386		$	96,183		$	4,887	$	96,040		$	4,908
Liabilities
Current liabilities:
Accounts payable	$	68	$	175		$	141		$	—	$	67		$	30
Taxes payable	11,745		2,205		(a)	19		(a)	10,774		4,732		(a)	10,857
Other accrued liabilities	2,380		3,084			2,358			2,810		2,311			2,884
Total current liabilities held for sale	14,193		5,464			2,518			13,584		7,110			13,771
Total liabilities held for sale	$	14,193	$	5,464		$	2,518		$	13,584	$	7,110		$	13,771


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

The ~~Company reclassified current income~~Company's deferred tax assets included in assets held for sale were largely comprised of ~~$47.5 million~~federal and ~~current income tax liabilities of $4.1 million to noncurrent assets - deferred income taxes at September 30, 2016, pursuant to the retrospective application~~state net operating loss carryforwards. The Company realized substantially all of the ~~adoption of the ASU related to the balance sheet classification of deferred taxes. For more information on this ASU, see Note 6.~~outstanding net operating loss carryforwards in 2017.

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 were included in operating expenses from discontinued operations. The estimated fair value of Fidelity's assets 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 $5.6 million of exit and disposal costs for the nine months ended September 30, 2016, and has incurred $10.5 million of exit and disposal costs to ~~date. Fidelity~~date and incurred no exit and disposal costs for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017, ~~and the~~respectively. 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 $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 second quarter of 2016.

matters.

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 ~~loss~~income from discontinued operations on the Company's Consolidated Statements of Income was as follows:


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018			2017
	(In thousands)												(In thousands)
Operating revenues	$	121		$	162		$	356		$	122,894		$	66		$	105
Operating expenses	384			230			(4,988		)	513,756			174			(6,577		)
Operating income (loss)	(263		)	(68		)	5,344			(390,862		)	(108		)	6,682
Other income (expense)	—			375			(13		)	762			12			(15		)
Interest expense	—			—			239			1,753			575			—
Income (loss) from discontinued operations before income taxes	(263		)	307			5,092			(391,853		)	(671		)	6,667
Income taxes	1,935			5,707			8,794			(92,315		)	(1,148		)	4,980			*
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	)
Income from discontinued operations													$	477		$	1,687


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

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

Note 910 - 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
Three Months Ended March 31, 2018							Balance at January 1, 2018		Goodwill Acquired During the Year		Balance at March 31, 2018
	(In thousands)						(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736	$	345,736	$	—	$	345,736
Construction materials and contracting	176,290		—		176,290		176,290		—		176,290
Construction services	109,765		—		109,765		109,765		—		109,765
Total	$	631,791	$	—	$	631,791	$	631,791	$	—	$	631,791


Nine Months Ended September 30, 2016	Balance at January 1, 2016		*	Goodwill Acquired During the Year		Balance at September 30, 2016		*
Three Months Ended March 31, 2017									Balance at January 1, 2017		Goodwill Acquired During the Year		Balance at March 31, 2017
	(In thousands)								(In thousands)
Natural gas distribution	$	345,736		$	—	$	345,736		$	345,736	$	—	$	345,736
Pipeline and midstream	9,737			—		9,737
Construction materials and contracting	176,290			—		176,290			176,290		—		176,290
Construction services	103,441			6,323		109,764			109,765		—		109,765
Total	$	635,204		$	6,323	$	641,527		$	631,791	$	—	$	631,791

* 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, 2017	Balance at January 1, 2017		Goodwill Acquired During the Year		Balance at December 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

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		March 31, 2018		March 31, 2017		December 31, 2017
	(In thousands)						(In thousands)
Customer relationships	$	15,248	$	17,145	$	17,145	$	14,668	$	15,745	$	15,248
Less accumulated amortization	13,176		13,524		13,917		13,007		12,910		13,382
	2,072		3,621		3,228		1,661		2,835		1,866
Noncompete agreements	2,430		2,430		2,430		2,430		2,430		2,430
Less accumulated amortization	1,769		1,622		1,658		1,842		1,695		1,805
	661		808		772		588		735		625
Other	7,020		7,764		7,768		6,458		7,086		6,990
Less accumulated amortization	5,544		5,664		5,843		5,242		5,309		5,644
	1,476		2,100		1,925		1,216		1,777		1,346
Total	$	4,209	$	6,529	$	5,925	$	3,465	$	5,347	$	3,837

Amortization expense for amortizable intangible assets for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017, was ~~$500,000~~$400,000 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 $1.9 million,~~ respectively. Estimated amortization expense for amortizable intangible assets is ~~$2.2 million in 2017, $1.2~~$1.3 million in 2018, $1.0 million in 2019, $500,000 in 2020, ~~$200,000~~$300,000 in 2021, $300,000 in 2022 and ~~$800,000~~$500,000 thereafter.

Note 1011 - 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 ~~$75.0~~$76.9 million, ~~$72.8~~$73.8 million and ~~$70.9~~$77.4 million, at ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized ~~gains~~loss on these investments ~~were $1.9 million and $6.9~~was $500,000 for the three months ended March 31, 2018. The net unrealized gain on these investments was $2.9 million for the three ~~and nine~~ months ended ~~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.~~March 31, 2017. The change in fair value, which is considered part of the cost of the plan, is classified in other income on the Company's Consolidated Statements of Income. In connection with the adoption of ASU 2017-07, as discussed in Note 6, the Company has elected to reclassify the unrealized gains and losses from operation and maintenance expense to other income on the Company's 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. The 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:


September 30, 2017	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
March 31, 2018										Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	9,488	$	11	$	(72	)	$	9,427	$	10,282	$	4	$	223	$	10,063
U.S. Treasury securities	613		—		(1		)	612		466		—		1		465
Total	$	10,101	$	11	$	(73	)	$	10,039	$	10,748	$	4	$	224	$	10,528


September 30, 2016	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
March 31, 2017										Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	9,882	$	43	$	(17	)	$	9,908	$	9,971	$	8	$	94	$	9,885
U.S. Treasury securities										412		1		—		413
Total	$	9,882	$	43	$	(17	)	$	9,908	$	10,383	$	9	$	94	$	10,298


December 31, 2016	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
December 31, 2017										Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	10,546	$	8	$	(105	)	$	10,449	$	10,342	$	4	$	129	$	10,217
U.S. Treasury securities										205		—		1		204
Total	$	10,546	$	8	$	(105	)	$	10,449	$	10,547	$	4	$	130	$	10,421

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 fair value 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 ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 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:


	Fair Value Measurements at September 30, 2017, Using								Fair Value Measurements at March 31, 2018, 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, 2017		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, 2018
	(In thousands)								(In thousands)
Assets:
Money market funds	$	—	$	6,204	$	—	$	6,204	$	—	$	9,085	$	—	$	9,085
Insurance contract*	—		74,991		—		74,991		—		76,941		—		76,941
Available-for-sale securities:
Mortgage-backed securities	—		9,427		—		9,427		—		10,063		—		10,063
U.S. Treasury securities	—		612		—		612		—		465		—		465
Total assets measured at fair value	$	—	$	91,234	$	—	$	91,234	$	—	$	96,554	$	—	$	96,554


*	The insurance contract invests approximately 5049 percent in fixed-income investments, 2322 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, 3 percent in target date investments and 2 percent in cash equivalents.



	Fair Value Measurements at March 31, 2017, 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, 2017
	(In thousands)
Assets:
Money market funds	$	—	$	2,551	$	—	$	2,551
Insurance contract*	—		73,775		—		73,775
Available-for-sale securities:
Mortgage-backed securities	—		9,885		—		9,885
U.S. Treasury securities	—		413		—		413
Total assets measured at fair value	$	—	$	86,624	$	—	$	86,624


*	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								Fair Value Measurements at December 31, 2017, 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		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, 2017
	(In thousands)								(In thousands)
Assets:
Money market funds	$	—	$	2,284	$	—	$	2,284	$	—	$	6,965	$	—	$	6,965
Insurance contract*	—		72,818		—		72,818		—		77,388		—		77,388
Available-for-sale securities:
Mortgage-backed securities	—		9,908		—		9,908		—		10,217		—		10,217
U.S. Treasury securities									—		204		—		204
Total assets measured at fair value	$	—	$	85,010	$	—	$	85,010	$	—	$	94,774	$	—	$	94,774


*	The insurance contract invests approximately 6549 percent in fixed-income investments, 1823 percent in common stock of large-cap companies, 914 percent in common stock of mid-cap companies, 611 percent in common stock of small-cap companies, 12 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.

~~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, 2018	$	1,779,542	$	1,854,350
Long-term debt at March 31, 2017	$	1,703,006	$	1,784,588
Long-term debt at December 31, 2017	$	1,714,853	$	1,826,256

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

~~Note 11 - Equity~~

~~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.

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



	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
Interest, net*	$	17,910		$	17,546
Income taxes refunded, net**	$	(1,056	)	$	(2,762	)


*	AFUDC - borrowed was $382,000 and $196,000 for the three months ended March 31, 2018 and 2017, respectively.


**	Income taxes paid (refunded), net of discontinued operations, were ~~$1.4~~$1.7 million and ~~$(144,000)~~$(7.2) million for the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively.

Noncash investing transactions were as follows:

September 30,
2017
2016
(In thousands)
Property, plant and equipment additions in accounts payable $ 16,914
$ 22,560

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~~operations mine, process and sell construction aggregates ~~and markets crushed~~(crushed stone, sand ~~gravel~~and gravel); produce and sell asphalt mix; and supply ready-mixed concrete. This segment focuses on vertical integration of its contracting services with its construction materials to support the aggregate based product lines including aggregate placement, asphalt and concrete paving, and site development and grading. Although not common to all locations, other products include the sale of cement, liquid asphalt for various commercial and roadway applications, various finished concrete products and other building materials 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 inside and outside specialty contracting services. Its outside services include design, construction and maintenance of overhead and underground electrical distribution and transmission lines, substations, external lighting, traffic signalization, and gas pipelines, as well as utility excavation and the manufacture and distribution of transmission line construction equipment. Its inside services ~~specializing in constructing~~include design, construction and ~~maintaining electric~~maintenance of electrical and communication ~~lines, gas pipelines,~~wiring and infrastructure, fire suppression systems, and ~~external lighting~~mechanical piping and ~~traffic signalization.~~services. This segment also ~~provides utility excavation~~constructs and ~~inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and other supplies.~~

maintains renewable energy projects. These specialty contracting services are provided to utilities and large manufacturing, commercial, industrial, institutional and government customers.

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~~self-insured layers of the insured ~~companies'~~Company's 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 8.9.

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~~2017 Annual Report. Information on the Company's ~~businesses~~segments was as follows:


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,												March 31,
	2017			2016			2017			2016			2018			2017
	(In thousands)												(In thousands)
External operating revenues:
Regulated operations:
Electric	$	91,531		$	82,156		$	254,330		$	238,911		$	87,404		$	88,225
Natural gas distribution	92,253			87,941			566,364			500,106			332,664			342,519
Pipeline and midstream	23,152			21,982			45,341			44,980			4,391			2,870
	206,936			192,079			866,035			783,997			424,459			433,614
Nonregulated operations:
Pipeline and midstream	5,356			10,732			13,518			29,697			4,442			3,643
Construction materials and contracting	686,010			724,535			1,388,212			1,475,643			213,284			200,776
Construction services	374,111			280,801			1,009,693			822,226			334,050			299,572
Other	135			420			654			1,167			58			320
	1,065,612			1,016,488			2,412,077			2,328,733			551,834			504,311
Total external operating revenues	$	1,272,548		$	1,208,567		$	3,278,112		$	3,112,730		$	976,293		$	937,925

Intersegment operating revenues:
Regulated operations:
Electric	$	—		$	—		$	—		$	—		$	—		$	—
Natural gas distribution	—			—			—			—			—			—
Pipeline and midstream	3,081			3,278			30,923			30,969			21,735			21,489
	3,081			3,278			30,923			30,969			21,735			21,489
Nonregulated operations:
Pipeline and midstream	38			41			132			161			24			34
Construction materials and contracting	142			155			400			370			101			86
Construction services	415			3			715			541			11			6
Other	1,910			2,204			5,411			5,542			2,638			1,743
	2,505			2,403			6,658			6,614			2,774			1,869
Intersegment eliminations	(5,586		)	(5,681		)	(37,581		)	(37,583		)	(24,509		)	(23,358		)
Total intersegment operating revenues	$	—		$	—		$	—		$	—		$	—		$	—


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,												March 31,
	2017			2016			2017			2016			2018			2017
	(In thousands)												(In thousands)
Earnings (loss) on common stock:
Earnings on common stock:
Regulated operations:
Electric	$	15,712		$	12,699		$	37,904		$	31,840		$	13,084		$	14,333
Natural gas distribution	(10,883		)	(12,524		)	14,181			4,940			32,623			27,861
Pipeline and midstream	5,853			5,389			15,901			16,241			5,459			4,557
	10,682			5,564			67,986			53,021			51,166			46,751
Nonregulated operations:
Pipeline and midstream	95			1,304			(770		)	2,043			(179		)	(628		)
Construction materials and contracting	63,221			69,523			64,477			88,747			(23,521		)	(19,912		)
Construction services	13,144			7,234			32,896			20,198			15,090			7,362
Other	552			(1,009		)	(1,888		)	(3,572		)	(596		)	(279		)
	77,012			77,052			94,715			107,416			(9,206		)	(13,457		)
Intersegment eliminations*	1,855			5,599			6,121			5,599			—			2,173
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 from discontinued operations													41,960			35,467
Income from discontinued operations, net of tax*													477			1,687
Total earnings on common stock													$	42,437		$	37,154

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


*	Includes an elimination 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~~qualified 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:

Pension Benefits
Other
Postretirement Benefits
Three Months Ended September 30, 2017
2016
2017
2016
(In thousands)
Components of net periodic benefit cost (credit):
Service cost $ —
$ —
$ 377
$ 412
Interest cost 4,052
4,305
816
922
Expected return on assets (5,132 ) (5,231 ) (1,160 ) (1,133 )
Amortization of prior service credit —
—
(343 ) (343 )
Amortization of net actuarial loss 1,589
1,553
213
371
Net periodic benefit cost (credit), including amount capitalized 509
627
(97 ) 229
Less amount capitalized 65
82
(95 ) (34 )
Net periodic benefit cost (credit) $ 444
$ 545
$ (2 ) $ 263



	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2018			2017			2018			2017
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	407		$	447
Interest cost	3,807			4,014			778			808
Expected return on assets	(4,998		)	(5,029		)	(1,167		)	(1,145		)
Amortization of prior service credit	—			—			(349		)	(343		)
Amortization of net actuarial loss	1,782			1,793			238			336
Net periodic benefit cost (credit), including amount capitalized	591			778			(93		)	103
Less amount capitalized	—			107			40			(39		)
Net periodic benefit cost (credit)	$	591		$	671		$	(133	)	$	142

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

The components of net periodic benefit cost (credit), other than the service cost component, are included in other income on the Company's Consolidated Statements of Income.

Nonqualified defined benefit plans

In addition to the qualified ~~plan~~ defined pension ~~benefits~~benefit plans reflected in the table, the Company also has unfunded, nonqualified defined 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 was $1.1 millionand $1.2 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017, ~~was $1.2 million and $3.5 million,~~ respectively. ~~The Company's~~In accordance with ASU 2017-07, the components of net periodic benefit cost, ~~for these plans for~~which does not contain any service costs, have been classified as other income on the ~~three and nine months ended September 30, 2016~~, ~~was$1.3 million and $600,000, respectively, which reflects a curtailment gain~~Company's Consolidated Statements of ~~$3.3 million in the first quarter of 2016.~~Income.

Note 15 - Regulatory matters

The Company regularly reviews the need for electric and natural gas rate changes in each of the jurisdictions in which service is provided. The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed by regulators. The Company's most recent cases by jurisdiction are discussed in the following paragraphs. The jurisdictions in which the Company provides service have requested the Company furnish plans for the effect of the reduced corporate tax rate due to the enactment of the TCJA which may impact the Company's rates. The following paragraphs include additional details on each jurisdiction's request.

IPUC

On ~~August~~January 17, 2018, the IPUC issued a general order initiating the investigation of the impacts of the TCJA. The order required the tax rate reduction to be deferred as a regulatory liability and for companies to report on the expected impacts of the TCJA by March 30, 2018. On March 12, ~~2016,~~2018, the Idaho governor signed into law a decrease in the state corporate income tax rate from 7.4 percent to 6.9 percent retroactive to January 1, 2018. On March 23, 2018, Intermountain filed an application ~~with~~and supporting tariffs incorporating the ~~IPUC for~~effects of the decreases in both federal and state income taxes resulting in a ~~natural gas rate increase~~decrease in revenues of approximately ~~$10.2~~$5.0 million ~~annually or approximately 4.1 percent above current rates. The request included rate recovery~~annually. Until the final order is received, a regulatory liability will be recorded, beginning on January 1, 2018, to capture the customer benefits 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. 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 filed a petition for reconsideration with the 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 14, 2017, with rates effective October 1, 2017.these lower taxes.

MNPUC

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. 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. On October 6,29, 2017, the MNPUC ~~approved~~issued a notice of investigation related to tax changes with the ~~implementation~~enactment of the ~~natural gas utility infrastructure cost tariff~~TCJA. On January 19, 2018, the MNPUC issued a notice of request for information, commission planning meeting and subsequent comment period. Pursuant to ~~collect an annual increase~~the notice, Great Plains provided preliminary impacts of ~~approximately $456,000.~~the TCJA on January 30, 2018. On March 2, 2018, Great Plains submitted ~~a compliance~~its initial filing ~~on October 10, 2017, requesting~~addressing the ~~order to be effective with service rendered on~~impacts of the TCJA and ~~after 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 withis advocating existing rates ~~effective November 1, 2017.~~

~~On June 30, 2017, Montana-Dakota filed an application for advance determination of prudence~~are reasonable 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 projectreduction in rates 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.

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.not warranted. This matter is pending before the ~~NDPSC.~~MNPUC.

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.MTPSC

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. On December 27, 2017, the MTPSC requested Montana-Dakota identify a plan for the impacts of the TCJA for the natural gas segment within the existing natural gas rate case. On January 12, 2018, Montana-Dakota filed a revised interim increase of approximately $764,000, subject to refund, incorporating the estimated impacts of the TCJA reduction in the federal corporate income tax rate. On February 23, 2018, supplemental testimony, regarding the effects of the TCJA, was submitted reducing Montana-Dakota's initial request of $2.8 million to $1.6 million. On March 6, 2018, the interim request for rate relief was denied by the MTPSC. On April 24, 2018, a stipulation was filed with the MTPSC reflecting an annual increase of $975,000 or 1.4 percent. A hearing was held on April 26, 2018. This matter is pending before the MTPSC.

On December 27, 2017, the MTPSC requested Montana-Dakota identify a plan for the impacts of the TCJA and to file a proposal for the impacts on the electric segment by March 31, 2018. On April 2, 2018, Montana-Dakota submitted its plan requesting the MTPSC recognize the identified need for additional rate relief and to consider the effects of the TCJA in a general electric rate case to be submitted by September 30, 2018. This matter is pending before the MTPSC.

NDPSC

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. On January 12, 2018, Montana-Dakota requested a delay of the rate case as a result of the enactment of the TCJA to allow the Company time to investigate the implications of the TCJA on the rate case. On February 14, 2018, the NDPSC approved the delay of hearing and scheduled it to begin on May 30, 2018. Also on February 14, 2018, Montana-Dakota filed a revised interim increase request of approximately $2.7 million, subject to refund, incorporating the estimated impacts of the TCJA reduction in the federal corporate income tax rate. On March 1, 2018, the updated interim rates were implemented. The impact of the TCJA was submitted as part of a rebuttal testimony identifying a reduction of the adjusted revenue requirement to $3.6 million. A hearing is scheduled for May 30, 2018. This matter is pending before the NDPSC.

On January 10, 2018, the NDPSC issued a general order initiating the investigation into the effects of the TCJA. The order required regulatory deferral accounting on the impacts of the TCJA and for companies to file comments and the expected impacts. On February 15, 2018, Montana-Dakota filed a summary of the primary impacts of the TCJA on the electric and natural gas utilities. On March 9, 2018, Montana-Dakota submitted a request to decrease its electric rates by $7.2 million or 3.9 percent annually. This matter is pending before the NDPSC.

OPUC

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~~This filing was withdrawn on March 6, 2018, and will be ~~effective January 1, 2018.~~incorporated into an upcoming rate increase filing.

On December 29, 2017, Cascade filed a request with the OPUC to use deferral accounting for the 2018 net benefits associated with the implementation of the TCJA. This matter is pending before the OPUC.

SDPUC

On December 29, 2017, the SDPUC issued an order initiating the investigation into the effects of the TCJA. The order required Montana-Dakota ~~previously~~to provide comments by February 1, 2018, regarding the general effects of the TCJA on the cost of service in South Dakota and possible mechanisms for adjusting rates. The order also stated that all rates impacted by the federal income tax shall be adjusted effective January 1, 2018, subject to refund. The Company expects to file detailed plans of the TCJA impact in the second quarter of 2018.

WUTC

On August 31, 2017, Cascade 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~~WUTC for a renewable resource cost adjustment rider, an electric generation resource recovery rider, and a transmission cost adjustment 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. A hearing on the settlement agreement 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 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 to reflect true-ups for the various 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 to be finalized upon approval of the electric rate case filed on October 14, 2016. The electric rate case settlement agreement filed on April 7, 2017, included a revised return on equity for the 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 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. 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 to be finalized upon approval of the electric rate case filed on October 14, 2016. The electric rate case settlement agreement filed on April 7, 2017, included a revised return on equity for the 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~~$5.9 million annually or ~~6.6~~approximately 2.7 percent above current rates. The ~~request~~requested increase includes ~~rate recovery~~costs associated with increased infrastructure investment and the associated operating expenses. Also included in ~~facilities, along with~~ the ~~related depreciation,~~request is recovery of operation and maintenance ~~expenses and taxes~~costs associated with a maximum allowable operating pressure validation plan. On January 3, 2018, the ~~increased investment.~~WUTC filed a bench request requiring Cascade to provide information related to the impacts of the TCJA on Cascade's revenue requirement and a proposed ratemaking treatment of those impacts. On March 23, 2018, Cascade filed its rebuttal testimony revising the revenue requirement to a decrease of $1.7 million annually, which includes the impacts of the TCJA. This matter is pending before the WUTC.

WYPSC

On December 29, 2017, the WYPSC issued a general order requiring regulatory deferral accounting on the impacts of the TCJA. A technical conference was held on February 6, 2018, to discuss the implications of the TCJA. On March 23, 2018, the WYPSC issued an order requiring all public utilities to submit an initial assessment of the overall effects on the TCJA on their rates by March 30, 2018. On March 30, 2018, Montana-Dakota submitted its initial assessment indicating a rate reduction for its electric rates in the amount of $1.1 million annually or 4.2 percent with a commitment to submit a request to revise electric rates by May 15, 2018. Montana-Dakota reported its natural gas earnings do not support a decrease in rates and requested the WYPSC allow the impacts of the TCJA be addressed in a natural gas rate case to be submitted by June 1, 2019. This matter is pending before the WYPSC.

FERC

Montana-Dakota and certain MISO Transmission Owners with projected rates submitted a filing to the FERC on February 1, 2018, requesting the FERC to waive certain provisions of the MISO tariff in order for Montana-Dakota and certain MISO Transmission Owners with projected rates to revise their rates to reflect the reduction in the corporate tax rate. Under the MISO tariff, rates are to be changed only on an ~~interim increase~~annual basis with any changes reflected in subsequent true-ups. On March 15, 2018, the FERC approved the waiver request and new rates reflecting the effects of ~~approximately $13.0~~the TCJA were implemented by MISO on March 1, 2018. MISO also retroactively re-billed the January and February 2018 services to reflect the new rates. The total revenue requirement for the Company's multivalue project was reduced to $12.0 million ~~or approximately 6.5 percent,~~from $13.6 million, which was previously effective on January 1, 2018.

The FERC has issued a notice of proposed rulemaking, subject to ~~refund,~~notice and comment, that will require pipeline companies to make a one-time informational filing to evaluate the impact of the lower corporate income tax rate and also select one of four options presented by FERC. On April 10, 2018, WBI Energy Transmission held an initial rate change pre-filing settlement meeting with customers. In accordance with WBI Energy Transmission’s offer of settlement and stipulation and agreement with the FERC dated June 4, 2014, the Company is to make a filing with new proposed rates to be effective ~~within 60 days of the filing. On November 21, 2016, Montana-Dakota filed and on November 30, 2016, the NDPSC approved~~no later than May 1, 2019. Assuming a ~~revised interim increase of approximately $11.7 million, based on adjustments accepted~~five-month suspension period, WBI Energy Transmission would expect to file by the NDPSC, or approximately 5.8 percent above current rates, subject to refund, effective with service rendered on or after December 13, 2016. A settlement agreement was filed on April 7, 2017, and subsequently approved on June 16, 2017, as previously discussed in this note.October 31, 2018.

Note 16 - Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated 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~~a

re 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 accrued liabilities of ~~$34.3~~$37.4 million, ~~$20.0~~$29.1 million and ~~$31.8~~$35.4 million, which have not been discounted, including liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, respectively. This includes amounts that may have been accrued for matters discussed in ~~Litigation and~~ Environmental matters within this note. The Company will continue to monitor each matter and adjust accruals as might be warranted based on new information and further developments. Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of insurance recoveries, while uncertain, either ~~can not~~cannot 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.

~~Litigation~~

~~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 aan 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. The Oregon DEQ released aan 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~~$400,000 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 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, December 1, 2016 and December 1, ~~2016.~~2017.

The second claim is for contamination at ~~a site~~the Bremerton Gasworks Superfund 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~~$1.8 million has been incurred. Cascade has accrued ~~$6.9~~$5.8 million for the remedial investigation and feasibility study as well as $6.4 million for remediation of this 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.

Guarantees

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 ~~$57.4~~$55.1 million at ~~September 30, 2017,~~March 31, 2018, and are expected to mature byin 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 ~~September 30, 2017,~~March 31, 2018, the fixed maximum amounts guaranteed under these agreements aggregated ~~$119.4~~$134.8 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate ~~$2.5 million in 2017; $21.3~~to $2.7 million in 2018; ~~$15.8~~$63.0 million in 2019; ~~$72.6~~$62.1 million in 2020; $500,000 in 2021; ~~$2.7~~$500,000 in 2022; $2.0 million thereafter; and $4.0 million, which has no scheduled maturity date. There were no amounts outstanding under the above guarantees at ~~September 30, 2017.~~March 31, 2018. 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 ~~September 30, 2017,~~March 31, 2018, the fixed maximum amounts guaranteed under these letters of credit aggregated $34.0 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate ~~$29.2~~$33.3 million in ~~2017~~2018 and ~~$4.8 million~~$700,000 in ~~2018.~~2019. There were no amounts outstanding under the above letters of credit at ~~September 30, 2017.~~March 31, 2018. 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 ~~September 30, 2017.~~March 31, 2018.

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 ~~September 30, 2017,~~March 31, 2018, approximately ~~$556.8~~$738.7 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.

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 that 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 ~~September 30, 2017,~~March 31, 2018, 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 ~~$41.4~~$40.3 million.

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

~~Overview~~The Company operates with a two-platform business model. Its regulated energy delivery platform and its construction materials and services platform are each comprised of different operating segments. Some of these segments experience seasonality related to the industries in which they operate. The two-platform approach helps balance this seasonality and the risk associated with each type of industry. Through its regulated energy delivery platform, the Company provides electric and natural gas services to customers, generates, transmits and distributes electricity, and provides natural gas transportation, storage and gathering services. These businesses are regulated by state public service commissions and/or the FERC. The construction materials and services platform provides construction services to a variety of industries, including commercial, industrial and governmental, and provides construction materials through aggregate mining and marketing of related products, such as ready-mix concrete and asphalt.

The Company is organized into five reportable business segments. These business segments include: electric, natural gas distribution, pipeline and midstream, construction materials and contracting, and construction services. The Company's reportable segments are determined 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 segments is defined based on the reporting and review process used by the Company's chief executive officer.

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:~~

~~Organic~~through organic growth ~~as well as~~opportunities and strategic acquisitions. The Company is focused on a ~~continued~~ disciplined approach to the acquisition of well-managed companies and ~~properties~~

The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization

~~The development of projects that are accretive to earnings per share and return on invested capital~~properties.

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

On December 22, 2017, President Trump signed into law the TCJA making significant changes to the United States federal income tax laws. Some of the more material changes from the TCJA impacting the Company included lower corporate tax rates, repealing the domestic production deduction, disallowance of immediate expensing for regulated utility property and modifying or repealing many other business deductions and credits. The Company continues to review the components of the TCJA and evaluating the impact on the Company for 2018 and thereafter. For information pertinent to the specific impacts or trends identified by the Company's business segments, see Business Segment Financial and Operating Data.

Consolidated Earnings Overview

The following table summarizes the contribution to the consolidated earnings by each of the Company's business segments.



	Three Months Ended
	March 31,
	2018			2017
	(In millions, except per share amounts)
Electric	$	13.1		$	14.3
Natural gas distribution	32.6			27.9
Pipeline and midstream	5.3			3.9
Construction materials and contracting	(23.5		)	(19.9		)
Construction services	15.1			7.4
Other	(.7		)	(.3		)
Intersegment eliminations	—			2.2
Earnings before discontinued operations	41.9			35.5
Income from discontinued operations, net of tax	.5			1.7
Earnings on common stock	$	42.4		$	37.2
Earnings per common share - basic:
Earnings before discontinued operations	$	.22		$	.18
Discontinued operations, net of tax	—			.01
Earnings per common share - basic	$	.22		$	.19
Earnings per common share - diluted:
Earnings before discontinued operations	$	.22		$	.18
Discontinued operations, net of tax	—			.01
Earnings per common share - diluted	$	.22		$	.19

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017 The Company recognized consolidated earnings of $42.4 million for the quarter ended March 31, 2018, compared to $37.2 million for the same period in 2017.

Positively impacting the Company's earnings were higher specialty contracting margins at the construction services business and higher natural gas retail sales margins at the natural gas distribution business. The earnings were negatively impacted by lower earnings at the construction materials and contacting business largely due to a reduced tax benefit as a result of the enactment of the TCJA. A discussion of key ~~strategies~~financial data from the Company's business segments activities follows.

Business Segment Financial and Operating Data

Following are key financial and operating data for each of the Company's business ~~segments~~segments. Also included are highlights on key growth strategies, projections and certain ~~related~~assumptions for the Company and its subsidiaries and other matters of the Company's business ~~challenges~~segments. Many of these highlighted points are ~~summarized below.~~"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, as well as the various important factors listed in Part I, Item 1A - Risk Factors in the 2017 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.

For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements. For a summary of the Company's business segments, see Note 13.

~~Key Strategies and Challenges~~

Electric and Natural Gas Distribution

Strategy and challenges ~~Provide~~The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Note 13. Both segments strive to be a top performing utility company measured by integrity, safety, employee satisfaction, customer service and shareholder return, while continuing to focus on providing safe, reliable and ~~reliable~~ competitively priced energy and related services to customers. The ~~electric and natural gas distribution~~Company continues to monitor opportunities for these 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. The continued efforts to create operational improvements and efficiencies across both segments promotes the Company's business integration strategy. The primary factors that impact the results of these segments are the ability to earn authorized rates of return, the cost of natural gas, cost of electric fuel and purchased power, competitive factors in the energy industry and economic conditions in the segments' service areas.

~~Challenges~~ ~~Both~~The electric and natural gas distribution segments are subject to extensive regulation in the ~~state~~ jurisdictions where they conduct operations with respect to costs, ~~and~~ timely recovery of investments and permitted returns on investment as well as ~~subject to~~ certain operational, system integrity and environmental regulations. ~~These~~To assist in the reduction of regulatory lag with the increase in investments, tracking mechanisms have been implemented. 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 result in the retirement of certain electric generating facilities before they are fully depreciated. Although the current administration has slowed environmental regulations, ~~can require substantial investment~~the segments continue to ~~upgrade facilities.~~ invest in facility upgrades to be in compliance with the existing and future regulations.

The ability ~~of these segments~~ to grow through acquisitions is subject to significant ~~competition.~~competition and acquisition premiums. In addition, the ability of ~~both~~the segments to grow their 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~~

Revenues are impacted by both customer growth and ~~regulatory initiatives~~usage, the latter of which is primarily impacted by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase ~~renewable energy resources and reduce GHG emissions could impact the price and~~ demand for electricity, especially among residential and commercial customers. Average consumption among natural gas customers has tended to decline as more efficient appliances and furnaces are installed, and as the Company has implemented conservation programs. Decoupling mechanisms in certain jurisdictions have been implemented to largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns on the Company's distribution margins.

Non-GAAP measures The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, adjusted gross margin, that is considered a non-GAAP financial measure as it relates to the Company's electric and natural gas distribution segments. The presentation of adjusted gross margin is intended to be a helpful supplemental measure for investors’ understanding of the segments' operating performance. This non-GAAP measure should not be considered as an alternative to, or more meaningful than, GAAP measures such as operating income (loss) or earnings (loss). The Company's adjusted gross margin measure may not be comparable to other companies’ gross margin measures.

In addition to operating revenues and ~~could result~~operating expenses, management also uses the non-GAAP measure of adjusted gross margin when evaluating the results of operations for the electric and natural gas distribution segments. Adjusted gross margin for the electric segment is calculated as operating revenue less cost of electric fuel and purchased power and certain taxes, other than income. Adjusted gross margin for the natural gas distribution segment is calculated as operating revenues less purchased natural

gas sold and certain taxes, other than income. Taxes, other than income included as a reduction to adjusted gross margin relate to revenue taxes. The segments pass on to their customers the increases and decreases in the ~~retirement~~wholesale cost of ~~certain electric generating facilities before~~power purchases, natural gas and other fuel supply costs in accordance with regulatory requirements. As such, the segments' revenues are directly impacted by the fluctuations in such commodities. Revenue taxes fluctuate with revenues as they are ~~fully depreciated.~~calculated as a percentage of revenues. Period over period, the segments' operating income (loss) is not impacted by the increase or decrease in revenues since the change is directly related to the increase or decrease in wholesale cost of power purchases, natural gas or other fuel supply costs, nor is it impacted by revenue taxes since it is a direct result of revenues. The Company's management believes the adjusted gross margin is an adequate supplemental measure as these items are included in both operating revenues and operating expenses. The Company's management also believes that adjusted gross margin and the remaining operating expenses that calculate operating income (loss) are useful in assessing the Company's utility performance as management has the ability to influence control over the remaining operating expenses.

The electric segment's operating income was $18.2 million and $22.3 million for the three months ended March 31, 2018 and 2017, respectively. Operating income for the three months ended March 31, 2018, is calculated as operating revenues of $87.4 million less operating expenses of $69.2 million. Operating income for the three months ended March 31, 2017, is calculated as operating revenues of $88.2 million less operating expenses of $65.9 million. Operating income decreased by $4.1 million due to lower operating revenues, largely the result of reserves against revenues to customers for lower income taxes due to the enactment of the TCJA and lower rate realization in certain jurisdictions partially offset by higher electric volumes. Also contributing to lower operating income were higher operation and maintenance expense and higher depreciation, depletion and amortization expense. The segment's operating income of $18.2 million is adjusted by adding back operation and maintenance expense of $30.1 million; depreciation, depletion and amortization expense of $12.6 million; and certain taxes, other than income of $3.8 million for the three months ended March 31, 2018, to calculate adjusted gross margin of $64.7 million. The segment's operating income of $22.3 million is adjusted by adding back operation and maintenance expense of $28.7 million; depreciation, depletion and amortization expense of $11.8 million; and certain taxes, other than income of $3.3 million for the three months ended March 31, 2017, to calculate adjusted gross margin of $66.1 million.

The natural gas distribution segment's operating income was $48.5 million and $51.4 million for the three months ended March 31, 2018 and 2017, respectively. Operating income for the three months ended March 31, 2018, is calculated as operating revenues of $332.6 million less operating expenses of $284.1 million. Operating income for the three months ended March 31, 2017, is calculated as operating revenues of $342.5 million less operating expenses of $291.1 million. Operating income decreased by $2.9 million due to lower operating revenues, largely the result of lower purchased natural gas sold passed through to customers. Also contributing to lower operating income were higher operation and maintenance expense and higher depreciation, depletion and amortization expense, partially offset by lower purchased natural gas sold and lower taxes, other than income. The segment's operating income of $48.5 million is adjusted by adding back operation and maintenance expense of $44.8 million; depreciation, depletion and amortization expense of $17.7 million; and certain taxes, other than income of $5.7 million for the three months ended March 31, 2018, to calculate adjusted gross margin of $116.7 million. The segment's operating income of $51.4 million is adjusted by adding back operation and maintenance expense of $41.0 million; depreciation, depletion and amortization expense of $17.1 million; and certain taxes, other than income of $5.0 million for the three months ended March 31, 2017, to calculate adjusted gross margin of $114.5 million.

Earnings overview - electric The following information summarizes the performance of the electric segment.



	Three Months Ended
	March 31,
	2018		2017
(Dollars in millions, where applicable)
Operating revenues	$	87.4	$	88.2
Electric fuel and purchased power	22.5		21.9
Taxes, other than income	.2		.2
Adjusted gross margin	64.7		66.1
Operating expenses:
Operation and maintenance	30.1		28.7
Depreciation, depletion and amortization	12.6		11.8
Taxes, other than income	3.8		3.3
Total operating expenses	46.5		43.8
Operating income	18.2		22.3
Earnings	$	13.1	$	14.3
Retail sales (million kWh):
Residential	374.0		355.8
Commercial	402.3		397.0
Industrial	142.3		141.9
Other	22.7		22.3
	941.3		917.0
Average cost of electric fuel and purchased power per kWh	$	.022	$	.022

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017 Electric earnings decreased $1.2 million (8 percent) as a result of:

Adjusted gross margin: Decrease of $1.4 million largely the result of reserves against revenues in certain jurisdictions to refund to customers lower income taxes due to the enactment of the TCJA and lower rate realization in certain jurisdictions. Partially offsetting these decreases were higher retail sales volumes of 3 percent driven by all customer classes.

Operation and maintenance:Increase of $1.4 million largely from higher payroll-related costs and timing of miscellaneous expenses.

Depreciation, depletion and amortization:Increase of $800,000 as a result of increased plant balances.

Taxes, other than income: Increase of $500,000 primarily due to higher property taxes.

Other income: Decrease of $400,000 as a result of lower returns on investments.

Interest expense: Increase of $400,000 due to increased long-term debt balances.

Income taxes: Decrease of $3.6 million due to the enactment of the TCJA reduced corporate tax rate, which had a favorable impact compared to the first quarter of 2017, and reduced pre-tax income. A majority of the reduction in income taxes are being reserved against revenues, as previously discussed, resulting in a minimal impact on overall earnings.

Earnings overview - natural gas distribution The following information summarizes the performance of the natural gas distribution segment.



	Three Months Ended
	March 31,
	2018		2017
(Dollars in millions, where applicable)
Operating revenues	$	332.6	$	342.5
Purchased natural gas sold	203.7		214.4
Taxes, other than income	12.2		13.6
Adjusted gross margin	116.7		114.5
Operating expenses:
Operation and maintenance	44.8		41.0
Depreciation, depletion and amortization	17.7		17.1
Taxes, other than income	5.7		5.0
Total operating expenses	68.2		63.1
Operating income	48.5		51.4
Earnings	$	32.6	$	27.9
Volumes (MMdk)
Retail sales:
Residential	28.1		28.1
Commercial	18.6		19.0
Industrial	1.4		1.6
	48.1		48.7
Transportation sales:
Commercial	.8		.7
Industrial	36.8		38.0
	37.6		38.7
Total throughput	85.7		87.4
Average cost of natural gas, including transportation, per dk	$	4.23	$	4.40

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017 Natural gas distribution earnings increased $4.7 million (17 percent) as a result of:

Adjusted gross margin: Increase of $2.2 million largely resulting from approved rate recovery. The change in adjusted gross margin includes the reserves against revenues in certain jurisdictions to refund to customers lower income taxes due to the enactment of the TCJA. Also included in adjusted gross margin were weather normalization mechanisms in certain jurisdictions to offset lower retail sales volumes of 1 percent.

Operation and maintenance:Increase of $3.8 million, largely from higher payroll-related costs, contract services and conservation expenses.

Depreciation, depletion and amortization: Increase of $600,000 primarily as a result of increased plant balances.

Taxes, other than income: Increase of $700,000 due to higher property taxes.

Other income: Increase of $200,000 due to higher returns on investments.

Interest expense: Comparable to the same period in prior year.

Income taxes: Decrease of $7.3 million largely due to the enactment of the TCJA, which reduced the corporate tax rate resulting in a favorable impact compared to the first quarter of 2017. A portion of the reduction in income taxes are being reserved against revenues, as previously discussed.

Outlook The Company expects these segments will grow rate base by approximately 6 percent annually over the next five years on a compound basis. Operations are spread across eight states where the Company expects customer growth to be higher than the national average. Customer growth is expected to grow by 1 percent to 2 percent per year. 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 natural gas systems.

In November 2017, the NDPSC approved the advance determination of prudence for the purchase of the Thunder Spirit Wind farm expansion. The Company, in February 2018, signed a purchase agreement to obtain ownership of the expansion and will finalize the purchase when the construction is complete in late 2018. With the addition of the expansion, the total Thunder Spirit Wind farm generation capacity will be approximately 155 MW and will increase the Company's electric generation portfolio to approximately 27 percent renewables based on nameplate ratings. The Company's integrated resource plans in North Dakota and Montana include additional generation projects in the 2025 timeframe.

In June 2016, the Company, along with a partner, began construction on a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota. The estimated capital investment for this project is $130 million to $150 million. All necessary easements have been secured and construction is well underway. The project is expected to be completed in 2019.

The Company continues to be focused on the regulatory recovery of its investments. The Company files for rate adjustments to seek recovery of operating costs and capital investments, as well as reasonable returns as allowed by regulators. The Company's most recent cases by jurisdiction are discussed in Note 15.

With the enactment of the TCJA, the state regulators in jurisdictions where the segments operate have requested companies submit plans for the estimated impact of the TCJA. As such, the segments used the deferral method of accounting for the revaluation of its regulated deferred tax assets and liabilities in the fourth quarter of 2017. The Company continues to work with the state regulators on plans for the impacts of the TCJA as discussed in Note 15. The Company anticipates the TCJA will negatively impact the segments' cash flows due to not being able to immediately expense utility property for tax purposes as well as lower deferred taxes.

The labor contract at Montana-Dakota with the IBEW was in effect through April 30, 2018, and the labor contract at Cascade with the ICWU was in effect through March 31, 2018, as reported in Items 1 and 2 - Business Properties - General in the 2017 Annual Report. Both labor contracts are currently in negotiations.

Pipeline and Midstream

Strategy and challenges ~~Utilize~~The pipeline and midstream segment provides natural gas transportation, gathering and underground storage services, as discussed in Note 13. The segment focuses on utilizing its extensive expertise in the ~~segment's existing expertise in~~design, construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of existing operations, ~~internal~~organic growth, and investments in ~~and acquisitions of~~ energy-related assets ~~and companies~~within or in close proximity to its current operating areas. ~~Incremental~~The segment focuses on the continual safety and ~~new~~reliability of its systems, which entails building and maintaining safe natural gas pipelines and facilities. The segment continues to evaluate growth opportunities ~~include: access to new energy sources for storage, gathering and transportation services;~~including the expansion of existing storage, gathering and transmission facilities; incremental pipeline projects, which expand pipeline capacity; and expansion of energy-related services in the region leveraging on core competencies.

The segment is exposed to energy price volatility which is impacted by the fluctuations in pricing, production and basis differentials of the energy market's commodities. Legislative and regulatory initiatives to increase pipeline safety regulations and reduce methane emissions could also impact the price and demand for natural gas.

The pipeline and midstream ~~business~~segment is subject to ~~include liquid pipelines~~extensive regulation including certain operational, system integrity and ~~processing activities.~~

~~ChallengesOngoing challenges for this~~environmental regulations as well as various permit terms and operational compliance conditions. The segment ~~include: energy price volatility; basis differentials; environmental and regulatory requirements; securing~~is charged with the ongoing process of reviewing existing permits and ~~easements;~~easements as well as securing new permits and easements as necessary to meet current demand and future growth opportunities. Exposure to pipeline opposition groups could also cause negative impacts on the segment with increased costs and potential delays to project completion.

The segment focuses on the recruitment and retention of a skilled ~~workforce;~~workforce to remain competitive and ~~competition~~provide services to its customers. The industry in which it operates relies on a skilled workforce to construct energy infrastructure and operate existing infrastructure in a safe manner. A shortage of skilled personnel can create a competitive labor market which could increase costs incurred by the segment. Competition from other pipeline and midstream ~~companies.~~companies can also have a negative impact on the segment.

On March 8, 2018, President Trump issued proclamations for additional import duties on steel and aluminum. The segment is currently evaluating the impact this will have on costs of materials used in construction projects and maintenance work.

Earnings overview - The following information summarizes the performance of the pipeline and midstream segment.



	Three Months Ended
	March 31,
	2018			2017
	(Dollars in millions)
Operating revenues	$	30.6		$	28.0
Operating expenses:
Operation and maintenance	15.0			13.7
Depreciation, depletion and amortization	4.3			4.1
Taxes, other than income	3.1			3.0
Total operating expenses	22.4			20.8
Operating income	8.2			7.2
Earnings	$	5.3		$	3.9
Transportation volumes (MMdk)	78.3			67.1
Natural gas gathering volumes (MMdk)	3.7			3.9
Customer natural gas storage balance (MMdk):
Beginning of period	22.4			26.4
Net withdrawal	(14.7		)	(11.4		)
End of period	7.7			15.0

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017 Pipeline and midstream earnings increased $1.4 million (36 percent) as a result of:

Revenues: Increase of $2.6 million, largely attributable to higher transportation revenues of $1.9 million as a result of organic growth projects completed in second quarter 2017, which contributed to record volumes of natural gas transported through its system.

Operation and maintenance:Increase of $1.3 million, primarily from higher nonregulated project costs and contract services partially offset by the reversal of coalbed asset retirement obligations related to a non-strategic asset sale.

Depreciation, depletion and amortization: Increase of $200,000 largely resulting from organic growth projects.

Taxes, other than income:Increase of $100,000 from higher property taxes.

Other income: Decrease of $400,000 as a result of lower returns on investments.

Interest expense: Comparable to the same period in prior year.

Income taxes: Decrease of $700,000 primarily due to a lower corporate tax rate resulting from the enactment of the TCJA.

Outlook The Company has continued to feel the effects of natural gas production at record levels which keeps downward pressure on natural gas prices in the near term. The Company continues to focus on growth and improving existing operations through organic projects in all areas in which it operates. The following describes recent growth projects.

Construction on the Company's Valley Expansion project, a 38-mile pipeline that will deliver natural gas supply to eastern North Dakota and far western Minnesota, is expected to begin in May 2018. The project, which is designed to transport 40 MMcf of natural gas per day, is under the jurisdiction of the FERC. In February 2018, the Company received an order issuing a certificate of public convenience and necessity from the FERC.

In June 2017, the Company announced plans to complete a Line Section 27 expansion project in the Bakken area of northwestern North Dakota. The project will include approximately 13 miles of new pipeline and associated facilities. The project, as designed, will increase capacity by over 200 MMcf per day and bring total capacity of Line Section 27 to over 600 MMcf per day. Construction is expected to begin in May 2018.

In 2017, the Company completed and placed into service the Charbonneau and Line Section 25 expansion projects, which include a new compression station as well as other compressor additions and enhancements at existing stations. Partly due to the completion of these two expansion projects, the Company's system transported a record volume of natural gas through its system in the first quarter of 2018.

The Company recently announced two additional natural gas pipeline growth projects. The Demicks Lake project, which includes approximately 14 miles of 20-inch pipe, which is located in McKenzie County, North Dakota. Construction is expected to begin in 2019, with an in-service date in the fall of 2019. An open season was recently completed and the Company has secured

sufficient capacity commitments for the project. The Company also had a successful open season on its Line Section 22 project in the Billings, Montana, area. This project is scheduled for construction in 2019, with an in-service date in late 2019. The project will increase capacity by 22.5 MMcf per day to serve incremental demand in Billings, Montana. The Company continues to consider additional growth projects to increase natural gas transportation capacity across its system.

The impact of the TCJA on the pipeline and midstream industry is uncertain. As such, the regulated pipeline is using the deferral method of accounting for the revaluation of its regulated deferred tax assets and liabilities. The Company continues to work with the FERC on plans for the impacts of the TCJA, as discussed in Note 15.

The labor contract with the IBEW that WBI Energy Transmission was negotiating, as reported in Items 1 and 2 - Business Properties - General in the 2017 Annual Report, has been ratified.

Construction Materials and Contracting

Strategy and challenges ~~Focus~~The construction materials and contracting segment provides an integrated set of construction services, as discussed in Note 13. The segment focuses on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; ~~strengthen~~strengthening the long-term, strategic aggregate reserve position through available purchase and/or lease opportunities; ~~enhance~~enhancing profitability through cost containment, margin discipline and vertical integration of the segment's operations; ~~develop~~development and ~~recruit~~recruitment of talented employees; and ~~continue~~continued 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~~segment's expertise.

~~Challenges~~ ~~Recruitment~~As one of the country's largest sand and ~~retention~~gravel producers, the segment will continue to strategically manage its nearly 1.0 billion tons of ~~key personnel~~aggregate reserves in all its markets, as well as take further advantage of being vertically integrated. The segment's 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.

The construction materials and contracting segment faces challenges that are not under the direct control of the business. The segment operates in geographically diverse and highly competitive markets. Competition can put negative pressure on the ability of the segment to earn a reasonable return. The segment is also subject to volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and ~~steel,~~steel. Such volatility can have a negative impact on the segment's margins. Other variables that can impact the segment's margins include adverse weather conditions, the timing of project starts or completion and declines or delays in new and existing projects due to the cyclical nature of the construction industry and federal infrastructure spending.

The segment also faces challenges in the recruitment and retention of employees. Trends in the labor market include an aging workforce and availability issues. The segment continues to face increasing pressure to reduce costs and the need for temporary employment because of the seasonality of the work performed in certain regions.

Earnings overview - The following information summarizes the performance of the construction materials and contracting segment.



	Three Months Ended
	March 31,
	2018			2017
	(Dollars in millions)
Operating revenues	$	213.4		$	200.9
Cost of sales:
Operation and maintenance	198.9			188.5
Depreciation, depletion and amortization	13.0			12.6
Taxes, other than income	7.8			7.2
Total cost of sales	219.7			208.3
Gross margin	(6.3		)	(7.4		)
Selling, general and administrative expense:
Operation and maintenance	17.6			17.6
Depreciation, depletion and amortization	.6			1.1
Taxes, other than income	1.8			1.8
Total selling, general and administrative expense	20.0			20.5
Operating loss	(26.3		)	(27.9		)
Loss	$	(23.5	)	$	(19.9	)
Sales (000's):
Aggregates (tons)	3,847			3,505
Asphalt (tons)	226			215
Ready-mixed concrete (cubic yards)	572			562

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017 Construction materials and contracting's seasonal loss increased $3.6 million (18 percent) as a result of:

Gross margin: Increase of $1.1 million resulting from higher construction margins, which were positively impacted by increased workloads in states that experienced favorable weather and strong demand in certain regions. Partially offsetting the higher construction margins were lower materials margins due to higher repair and maintenance costs affecting aggregates and asphalt product margins and unfavorable weather in certain regions affecting the asphalt product margins.

Selling, general and administrative expense:Decrease of $500,000 largely resulting from lower depreciation, depletion, and amortization.

Other income: Decrease of $1.0 million as a result of lower returns on investments.

Interest expense: Comparable to the same period in prior year.

Income taxes: Decrease in income tax benefits of $4.1 million in the first quarter of 2018, which includes $3.9 million due to the enactment of the TCJA, that lowered the corporate tax rate.

Outlook The segment's vertically integrated aggregates based business model provides the Company with the ability to capture margin throughout the sales delivery process. The aggregate products are ~~ongoing challenges. This business unit expects~~sold internally and externally for use in other products such as ready-mixed concrete, asphaltic concrete and public and private construction markets. The contracting services and construction materials are sold primarily to construction contractors in connection with street, highway and other public infrastructure projects, as well as private commercial and residential development projects. The public infrastructure projects have traditionally been more stable markets as public funding is more secure during periods of economic decline. The public funding is, however, dependent on state and federal funding such as appropriations to the Federal Highway Administration. Spending on private development is highly dependent on both local and national economic cycles, providing additional sales during times of strong economic cycles.

The Company remains optimistic about overall economic growth and infrastructure spending. The IBIS World Industry Report for sand and gravel mining in the United States projects a 2.7 percent annual growth rate over the next five years. The report also states the demand for clay and refractory materials is projected to continue ~~cost containment efforts, positioning its operations for~~deteriorating in several downstream manufacturing industries, but this decline will be offset by stronger demand from the ~~resurgence~~housing market and buoyant demand from the highway and bridge construction market. This stronger demand in the ~~private market, while continuing~~housing markets along with continued demand from the ~~emphasis on industrial, energy~~highway and ~~public works projects.~~bridge construction markets should provide a stable demand for construction materials and contracting products and services in the near future.

Subsequent to March 31, 2018, the Company announced that it acquired Teevin & Fischer Quarry, a crushed rock and gravel supplier in northwestern Oregon, and it continues to evaluate additional acquisition opportunities.

The construction materials and contracting backlog at March 31, 2018, was $691.9 million, down from $724.6 million at March 31, 2017. The decrease in backlog was primarily attributable to lower state agency work.

The impact of the TCJA on the economy as a whole is unclear at this time. As such, the impact to the construction materials and contracting industry is also uncertain. Under the TCJA, the domestic production deduction is no longer available. The domestic production deduction was originally introduced to incentivize domestic production activities and was a deduction of up to 9 percent on qualified production activity income for which this segment's activities qualified. The Company expects the lower federal corporate tax rate will more than offset the loss of the domestic production deduction for this segment.

The labor contract that Knife River was negotiating, as reported in Items 1 and 2 - Business Properties - General in the 2017 Annual Report, has been ratified.

Construction Services

Strategy and challenges ~~Provide~~The construction services segment provides inside and outside specialty contracting, as discussed in Note 13. The construction services segment focuses on providing a superior return on investment ~~by:~~by building new and strengthening existing customer relationships; ensuring quality service; safely executing projects; effectively controlling costs; collecting on receivables; 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~~The construction services segment ~~operates~~faces challenges in the highly competitive markets ~~with many jobs subject to competitive bidding. Maintenance~~in which it operates. Competitive pricing environments, project delays and the effects of ~~effective operational and cost controls, retention of key personnel, managing through downturns~~restrictive regulatory requirements have negatively impacted margins in the ~~economy~~past and ~~effective management~~could affect margins in the future. Additionally, margins may be negatively impacted on a quarterly basis due to adverse weather conditions, as well as timing of ~~working~~project starts or completions, declines or delays in new projects due to the cyclical nature of the construction industry and other factors. These challenges may also impact the risk of loss on certain projects. Accordingly, operating results in any particular period may not be indicative of the results that can be expected for any other period.

The need to ensure available specialized labor resources for projects also drives strategic relationships with customers and project margins. These trends include an aging workforce and labor availability issues, increasing pressure to reduce costs and improve reliability, and increasing duration and complexity of customer capital ~~are ongoing challenges.~~

~~Additional Information~~

~~For more information on the risks and challenges the Company faces as it pursues its growth strategies~~programs. Due to these and other factors, ~~that should be considered~~we believe customer demand for ~~a better understanding~~labor resources will continue to increase, possibly surpassing the supply of industry resources.

Earnings overview - The following information summarizes the performance 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.construction services segment.

~~Earnings Overview~~

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

Three Months Ended Nine Months Ended
September 30, September 30,
2017
2016
2017
2016
(In millions, except per share amounts)
Electric $ 15.7
$ 12.7
$ 37.9
$ 31.8
Natural gas distribution (10.9 ) (12.5 ) 14.2
4.9
Pipeline and midstream 6.0
6.7
15.1
18.3
Construction materials and contracting 63.2
69.5
64.5
88.8
Construction services 13.1
7.2
32.9
20.2
Other .6
(1.0 ) (1.9 ) (3.6 )
Intersegment eliminations 1.9
5.6
6.1
5.6
Earnings before discontinued operations 89.6
88.2
168.8
166.0
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 )
Earnings (loss) on common stock $ 87.4
$ 82.8
$ 165.1
$ (1.8 )
Earnings (loss) per common share - basic:

Earnings before discontinued operations $ .46
$ .45
$ .86
$ .85
Discontinued operations attributable to the Company, net of tax (.01 ) (.03 ) (.01 ) (.86 )
Earnings (loss) per common share - basic $ .45
$ .42
$ .85
$ (.01 )
Earnings (loss) per common share - diluted:

Earnings before discontinued operations $ .46
$ .45
$ .86
$ .85
Discontinued operations attributable to the Company, net of tax (.01 ) (.03 ) (.02 ) (.86 )
Earnings (loss) per common share - diluted $ .45
$ .42
$ .84
$ (.01 )



	Three Months Ended
	March 31,
	2018		2017
	(In millions)
Operating revenues	$	334.1	$	299.6
Cost of sales:
Operation and maintenance	278.0		253.7
Depreciation, depletion and amortization	3.5		3.6
Taxes, other than income	12.8		12.1
Total cost of sales	294.3		269.4
Gross margin	39.8		30.2
Selling, general and administrative expense:
Operation and maintenance	17.3		16.1
Depreciation, depletion and amortization	.4		.4
Taxes, other than income	1.4		1.2
Total selling, general and administrative expense	19.1		17.7
Operating income	20.7		12.5
Earnings	$	15.1	$	7.4

Three Months Ended ~~September 30, 2017 and 2016~~ ~~The Company recognized consolidated earnings of $87.4 million for the quarter ended September 30, 2017, compared~~March 31, 2018 Compared to ~~$82.8 million from the comparable prior period largely due to:~~

~~Higher outside and inside construction margins at the construction services business~~

~~Higher electric retail sales margins at the electric business~~

~~Higher natural gas retail sales margins at the natural gas distribution business~~

~~These increases were partially offset by:~~

~~Lower asphalt product margins and lower construction margins at the construction materials and contracting business~~

~~Lower gathering and processing revenues at the pipeline and midstream business~~

~~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:~~

~~Discontinued operations which reflects the absence in 2017 of a loss associated with the sale of the refining business, which was sold in June 2016~~

~~Higher inside and outside construction margins at the construction services business~~

~~Higher natural gas retail sales margins at the natural gas distribution business~~

~~Higher electric retail sales margins at the electric business~~

~~These increases were partially offset by:~~

~~Lower asphalt product margins and lower construction margins at the construction materials and contracting business~~

~~Lower gathering and processing revenues at the pipeline and midstream business~~

~~Financial and Operating Data~~

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

~~Electric~~

Three Months Ended Nine Months Ended
September 30, September 30,
2017
2016
2017
2016
(Dollars in millions, where applicable)
Operating revenues $ 91.5
$ 82.2
$ 254.3
$ 238.9
Operating expenses:

Operation and maintenance 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 12.2
12.5
35.5
37.8
Taxes, other than income 3.7
3.6
11.1
10.2
65.2
61.8
191.6
187.4
Operating income 26.3
20.4
62.7
51.5
Earnings $ 15.7
$ 12.7
$ 37.9
$ 31.8
Retail sales (million kWh):
Residential 278.7
276.6
860.2
835.7
Commercial 377.7
373.3
1,122.7
1,089.5
Industrial 133.7
126.0
395.9
401.9
Other 28.5
23.3
75.7
66.5
818.6
799.2
2,454.5
2,393.6
Average cost of electric fuel and purchased power per kWh $ .021
$ .019
$ .022
$ .021

Three Months Ended ~~September 30,~~March 31, 2017 ~~and 2016~~ Electric earnings increased $3.0 million (24 percent) compared to the comparable prior period. The increase was largely the result of higher electric retail sales margins due to approved rate recovery, recovery of additional investment in a MISO multivalue project and higher retail sales volumes of 2 percent to all customer classes.

~~Partially offsetting the increase were:~~

~~Higher operation and maintenance expense of $1.0 million (after tax), largely higher payroll-related costs, contract services and material costs~~

~~Lower tax credits of $700,000~~

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

Higher electric retail sales margins, largely due to the recovery of additional investment in a MISO multivalue project, approved rate recovery and increased retail sales volumes of 3 percent, primarily to commercial and residential customers

~~Lower depreciation, depletion and amortization expense of $1.4 million (after tax) due to lower depreciation rates implemented in conjunction with regulatory recovery activity~~

~~Partially offsetting these increases were:~~

~~Higher operation and maintenance expense of $1.7 million (after tax), largely higher payroll-related costs and material costs~~

~~Higher taxes, other than income, which includes $500,000 (after tax) largely due to higher property taxes in certain jurisdictions~~

~~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

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

~~Three Months Ended 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 $9.3 million (187 percent) compared to the comparable prior period due to:~~

Higher natural gas retail sales margins resulting from higher retail sales volumes of 18 percent to all customer classes, driven primarily by colder weather in all jurisdictions and customer growth, as well as approved rate 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 these increases were:~~

~~Higher operation and maintenance expense, which includes $1.8 million (after tax) primarily due to higher payroll-related costs~~

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

~~Pipeline and Midstream~~

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

~~Three Months Ended September 30, 2017 and 2016~~ Pipeline and midstream earnings decreased $700,000 (11 percent) compared to the comparable prior period. The decrease was primarily the result of lower gathering and processing revenues of $3.6 million (after tax), largely due to lower volumes resulting from the sale of Pronghorn in January 2017.

~~Partially offsetting the decrease were:~~

~~Lower depreciation, depletion and amortization expense of $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 $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 Nine Months Ended
September 30, September 30,
2017
2016
2017
2016
(Dollars in millions)
Operating revenues $ 686.1
$ 724.7
$ 1,388.6
$ 1,476.0
Operating expenses:

Operation and maintenance 555.2
582.2
1,198.3
1,243.4
Depreciation, depletion and amortization 14.0
14.4
42.1
44.3
Taxes, other than income 12.0
12.2
32.9
33.7
581.2
608.8
1,273.3
1,321.4
Operating income 104.9
115.9
115.3
154.6
Earnings $ 63.2
$ 69.5
$ 64.5
$ 88.8
Sales (000's):

Aggregates (tons) 10,078
9,997
20,957
21,281
Asphalt (tons) 3,009
3,507
5,054
5,959
Ready-mixed concrete (cubic yards) 1,098
1,146
2,697
2,840

~~Three Months Ended September 30, 2017 and 2016~~ ~~Construction materials and contracting earnings decreased $6.3 million (9 percent) compared to the comparable prior period due to:~~

~~Lower asphalt product margins primarily due to increased competition in certain regions and less available work resulting in lower volumes~~

~~Lower construction margins of $1.5 million (after tax) primarily resulting from lower revenues in energy producing states due to less available work~~

~~Partially offsetting these decreases were:~~

~~Higher aggregate margins of $1.4 million (after tax), primarily resulting from higher sales volumes due to increased demand and timing of projects in the quarter~~

~~Higher other product line margins of $500,000 (after tax)~~

~~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:~~

~~Lower asphalt product margins primarily due to weather-related delays, less available work and increased competition in certain regions resulting in lower volumes~~

Lower construction margins of $8.9 million (after tax) primarily due to lower revenues resulting from poor weather conditions in the first half of 2017, project timing, less available work in energy producing states and increased competition

~~Lower ready-mixed concrete margins of $1.7 million (after tax) due to lower volumes primarily resulting from poor weather conditions and decreased demand in certain regions~~

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

~~Construction Services~~

Three Months Ended Nine Months Ended
September 30, September 30,
2017
2016
2017
2016
(In millions)
Operating revenues $ 374.5
$ 280.8
$ 1,010.4
$ 822.8
Operating expenses:

Operation and maintenance 336.4
255.8
906.1
750.1
Depreciation, depletion and amortization 3.9
3.9
11.9
11.4
Taxes, other than income 11.8
9.3
36.7
29.7
352.1
269.0
954.7
791.2
Operating income 22.4
11.8
55.7
31.6
Earnings $ 13.1
$ 7.2
$ 32.9
$ 20.2

~~Three Months Ended September 30, 2017 and 2016~~Construction services earnings increased ~~$5.9~~$7.7 million ~~(82~~(105 percent) ~~compared to the comparable prior period due to:~~as a result of:

~~Higher earnings~~Gross margin: Increase of $9.6 million resulting from higher ~~outside~~customer demands driven by the additional number and size of construction ~~margins due~~projects in 2018 and decreased labor costs attributable to successful job performance. Also contributing to the increase were higher ~~construction~~ workloads in areas impacted by ~~hurricane~~storm activity and higher outside equipment sales and ~~rentals~~rentals.

~~Higher earnings~~

Selling, general and administrative expense: Increase of ~~$3.4~~$1.4 million, ~~(after tax) resulting from higher inside construction margins largely the~~primarily payroll-related and outside professional costs.

Other income: Decrease of $300,000 as a result of ~~higher workloads~~lower returns on investments.

Interest expense: Comparable to the same period in prior year.

Income taxes: Lower due to the enactment of the TCJA, which reduced the corporate tax rate creating a favorable impact compared to the first quarter of 2017, partially offset by an increase in income before taxes in 2018.

Outlook The Company continues to expect long-term growth in the electric transmission market, although the timing of large bids and subsequent construction is likely to be highly variable from year to year. The Company believes several projects will be available for bid in the 2018 timeframe and also expects bidding activity in small and medium-sized projects to continue in 2018.

The Company experienced record revenues in the first quarter of 2018 and more than doubled its earnings. The Company expects bidding activity to remain strong in both outside and inside specialty construction companies for the year 2018. Although bidding remains highly competitive in all areas, the Company expects the segment's skilled workforce will continue to provide a benefit in securing and executing profitable projects. The construction services backlog at March 31, 2018, was $674.7 million, up from $529.1 million at March 31, 2017. The increase in backlog was primarily attributable to an increase in ~~large~~ projects ~~during~~from all revenue streams based on customer demand. Additionally, the ~~quarter~~Company continues to evaluate potential acquisition opportunities.

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

~~Nine Months Ended September 30, 2017 and 2016~~ ~~Construction services earnings increased $12.7 million (63 percent) compared~~the TCJA on the economy as a whole is unclear at this time. As such, the impact to the ~~comparable prior period due to:~~

~~Higher earnings~~construction services industry is also uncertain. While it is unclear what impact the TCJA may have on the construction services industry, the Company is optimistic about overall economic growth and infrastructure spending and believes that improving industry activity will continue in both market segments and the drivers for investment will remain intact. As the Company continues to experience growth in their operations, the impacts of ~~$14.5 million (after tax) resulting from higher inside construction margins~~the lower corporate tax rate offsets the increase in taxes on operating income. The Company believes that regulatory reform, state renewable portfolio standards, the aging of the electric grid, and the general improvement of the economy will positively impact the level of spending by its customers. Although competition remains strong, these trends are viewed as positive factors in the ~~majority of business activities performed which includes an increase~~future.

The ten labor contracts that the MDU Construction Services was negotiating, as reported in Items 1 and 2 - Business Properties - General in the ~~number and size of projects that moved into full construction in~~ 2017 ~~and successful execution of labor performance on projects~~

~~Higher earnings resulting from higher outside construction margins due to higher workloads including areas impacted by hurricane activity~~

~~Partially offsetting these increases were:~~

~~Higher selling, general and administrative expense of $3.3 million (after tax), primarily higher payroll-related costs~~

~~Absence in 2017 of a tax benefit of $1.5 million related to the disposition of a non-strategic asset~~Annual Report, have been ratified.

Other


	Three Months Ended					Nine Months Ended						Three Months Ended
	September 30,											March 31,
	2017		2016			2017			2016			2018			2017
	(In millions)											(In millions)
Operating revenues	$	2.1	$	2.7		$	6.1		$	6.7		$	2.7		$	2.1
Operating expenses:
Operation and maintenance	.1		2.4			5.7			6.3			2.0			1.2
Depreciation, depletion and amortization	.5		.5			1.5			1.6			.6			.6
Taxes, other than income	—		.1			.1			.1
	.6		3.0			7.3			8.0
Operating income (loss)	1.5		(.3		)	(1.2		)	(1.3		)
Earnings (loss)	$	.6	$	(1.0	)	$	(1.9	)	$	(3.6	)
Total operating expenses												2.6			1.8
Operating income												.1			.3
Loss												$	(.7	)	$	(.3	)

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 September 30, 2017 and 2016~~ Other experienced earnings of $600,000 compared to a loss 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 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.

~~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, as previously discussed, offset in part by a loss on the disposition of certain assets.

Discontinued Operations

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 )



	Three Months Ended
	March 31,
	2018		2017
	(In millions)
Income from discontinued operations before intercompany eliminations, net of tax	$	.5	$	3.9
Intercompany eliminations	—		(2.2		)	*
Income from discontinued operations, net of tax	$	.5	$	1.7

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


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

~~Three Months Ended September 30, 2017 and 2016~~ ~~The Company's loss from discontinued operations was $2.2 million compared to a loss of $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 decreased loss was largely due to the absence in 2017 of a loss associated with the sale of the refining 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~~related to these items ~~are~~were as follows:


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,												March 31,
	2017			2016			2017			2016			2018		2017
	(In millions)												(In millions)
Intersegment transactions:
Operating revenues	$	5.6		$	5.7		$	37.6		$	37.6		$	24.5	$	23.4
Purchased natural gas sold													21.7		21.5
Operation and maintenance	2.5			2.4			6.6			6.7			2.8		1.9
Purchased natural gas sold	3.1			3.3			31.0			30.9
Income from continuing operations*	(1.9		)	(5.6		)	(6.1		)	(5.6		)
Income from continuing operations													—		(2.2		)	*

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


*	Includes an elimination 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~~

•

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 power from the expansion of the Thunder Spirit Wind farm in southwest North Dakota. The agreement 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 will include 16 turbines, and is expected to be on line in December 2018. 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 filed its 2017 North Dakota Electric Integrated Resource Plan and 2017 Montana Electric Integrated Resource Plan in June 2017 and 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 combined-cycle, natural gas-fired facility to be expected in 2025 or later.


•	~~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.~~

The Company continues to be focused on the regulatory recovery of its investments. Since January 1, 2017, the Company has implemented final rate increases totaling $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, Oregon and Washington. Recently approved final rates include:


◦	~~On September 1, 2017, the Company submitted an update to its transmission formula rate under the 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 NDPSC for a natural gas rate increase, as discussed in Note~~ 15.


◦	~~On August 31, 2017, the Company filed an application with the WUTC for a natural gas rate increase, as discussed in Note~~ 15.


◦	~~On September 25, 2017, the Company filed an application with the MTPSC for a natural gas rate increase, as discussed in Note~~ 15.


◦	~~On September 29, 2017, the Company filed an application with the OPUC for an annual pipeline replacement safety cost recovery mechanism, 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 late 2018.


•	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 the Bakken producing area in northwestern North Dakota. The project will include approximately 13 miles of new pipeline and associated facilities. The project, as 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 fall of 2018. The Company has signed long-term contracts supporting this expansion and expects construction costs to range from $27 million to $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~~ ~~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 lower as compared to 2016 margins.~~


•	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, six have been ratified. The one remaining contract is still in negotiations.

~~Construction services~~


•	~~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 to provide service to the transmission, distribution, substations, utility services, industrial, commercial, high-technology, mission critical, manufacturing, institutional, hospitality, gaming, entertainment, infrastructure, and 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 ~~September 30, 2017,~~March 31, 2018, the Company had cash and cash equivalents of ~~$37.4~~$58.8 million and available borrowing capacity of ~~$663.3~~$622.5 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.~~debt; and the issuance of equity securities.

Cash flows

Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Business Segment 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 ~~nine~~three months of ~~2017 decreased $4.6~~2018 increased $19.3 million from the comparable period in ~~2016.~~2017.

Increases: The ~~decrease~~increase in cash flows provided by operating activities was largely ~~related~~at the electric and natural gas distribution businesses. The increase was primarily driven by the absence in 2018 of a deposit for the preferred stock redemption in 2017; the change in natural gas costs refundable; and the use of a prepaid gas contract resulting in lower gas purchases in the first quarter of 2018.

Decreases: Partially offsetting the increase were higher asphalt oil inventory balances at the construction materials and contracting business; changes relating to ~~higher working~~the balances of capital ~~requirements~~expenditures in accounts payable at the electric business; increased payables due to increases in overall operations at the construction services ~~business resulting from higher workloads.~~business; and regulatory change in the decoupling mechanism at the natural gas distribution business.

Investing activities Cash flows used in investing activities in the first ~~nine~~three months of 2018 was $100.2 million compared to cash flows provided by investing activities in the first three months of 2017 ~~decreased $155.4~~of $45.6 million. The change was primarily related to the net proceeds from the ~~comparable period~~sale of Pronghorn at the pipeline and midstream business in ~~2016.~~2017 along with higher utility construction expenditures at the electric and natural gas distribution businesses.

Financing activities Cash flows provided by financing activities in the first three months of 2018 was $18.6 million compared to cash flows used by financing activities of $127.5 million in the first three months of 2017. The ~~decrease~~change was largely the result of

lower repayment of long-term debt of $110.2 million primarily due to ~~net~~the use of 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 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 nine months of 2017 increased $135.5 million from the comparable period in 2016. The change was primarily due to lower~~higher issuance of long-term debt of $41.6 million, largely relating to changes in 2017 of $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.commercial paper balances.

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~~2017 Annual Report. For more information, see Note 14 and Part II, Item 7 in the ~~2016~~2017 Annual Report.

Capital expenditures

Capital expenditures for the first ~~nine~~three months of ~~2017~~2018 were ~~$217.1~~$93.0 million. Capital expenditures allocated to the Company's business segments are estimated to be approximately ~~$342~~$631 million for ~~2017, which does not include additional growth capital of $150 million.~~2018. The ~~additional growth capital is not allocated to a specific business segment and will be invested based on~~Company has included in the ~~risk-adjusted return potential of opportunities and is dependent upon the timing of such opportunities. The~~ estimated capital expenditures for ~~2017 include:~~2018 the purchase of the Thunder Spirit Wind farm expansion, the Valley Expansion project and the Line Section 27 expansion project, as previously discussed in Business Segment Financial and Operating Data.

~~System upgrades~~

~~Routine replacements~~

~~Service extensions~~

~~Routine~~Estimated capital expenditures for 2018 also include those for system upgrades; service extensions; routine equipment maintenance and ~~replacements~~

~~Buildings,~~replacements; buildings, land and building ~~improvements~~

~~Pipeline,~~improvements; pipeline, gathering and other midstream ~~projects~~

~~Power~~projects; power generation and transmission opportunities,

~~Environmental upgrades~~

~~Other~~ including certain costs for additional electric generating capacity; environmental upgrades; and other growth ~~opportunities~~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~~estimate previously discussed. It is anticipated that all of the funds required for capital expenditures ~~referred to previously. The Company expects~~for the ~~2017 estimated capital expenditures to~~2018 will be ~~funded by~~met from various sources, including internally generated funds; the Company's credit facilities, as described ~~in Capital resources; through the~~later; issuance of long-term debt; and ~~asset sales.~~issuance of equity securities.

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 ~~September 30, 2017.~~March 31, 2018. 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~~2017 Annual Report.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at ~~September 30, 2017:~~March 31, 2018:


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		$	43.4	(b)	$	—		5/8/19	Commercial paper/Revolving credit agreement	(a)	$	175.0		$	84.7	(b)	$	—		5/8/19
Cascade Natural Gas Corporation	Revolving credit agreement		$	75.0	(c)	$	10.0		$	2.2	(d)	4/24/20	Revolving credit agreement		$	75.0	(c)	$	5.9		$	2.2	(d)	4/24/20
Intermountain Gas Company	Revolving credit agreement		$	85.0	(e)	$	39.9		$	—		4/24/20	Revolving credit agreement		$	85.0	(e)	$	14.4		$	—		4/24/20
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	76.2	(b)	$	—		9/23/21	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	105.3	(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 $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 $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 4.3 times, 4.1 times ~~3.7 times~~ and ~~3.9~~4.2 times for the 12 months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, respectively.

Total equity as a percent of total capitalization was 5758 percent, 5558 percent and 5659 percent at ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ and December 31, ~~2016,~~2017, 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 September 30, 2017, which reduced the remaining capacity under this uncommitted private shelf agreement to $100.0 million.

Off balance sheet arrangements

As of ~~September 30, 2017,~~March 31, 2018, 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 2018 from those reported in the ~~2016~~2017 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the ~~2016~~2017 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~~2017 Annual ~~Report.~~Report other than the addition of a critical accounting policy involving revenue recognition due to the adoption of the new guidance, as discussed in Note 6. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the ~~2016~~2017 Annual Report.

Revenue recognition

Revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The recognition of revenue requires the Company to make estimates and assumptions that affect the reported amounts of revenue.

To determine the proper revenue recognition method for contracts, the Company evaluates whether two or more contracts should be combined and accounted for as one single contract and whether the combined or single contract should be accounted for as more than one performance obligation. This evaluation requires significant judgment and the decision to combine a group of contracts or separate the combined or single contract into multiple performance obligations could change the amount of revenue and profit recorded in a given period. For most contracts, the customer contracts with the Company to provide a significant service of integrating a complex set of tasks and components into a single project or capability. Hence, the Company's contracts are generally accounted for as one performance obligation.

The Company recognizes construction contract revenue over time using the cost-to-cost measure of progress for contracts because it best depicts the transfer of assets to the customer which occurs as the Company incurs costs on the contract. Under the cost-to-cost measure of progress, the costs incurred are compared with total estimated costs of a performance obligation. Revenues are recorded proportionately to the costs incurred. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs. Inasmuch as contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners. Changes in estimates could have a material effect on the Company's results of operations, financial position and cash flows.

Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates. As a project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions surrounding the job become known. If a loss is anticipated on a contract, the loss is immediately recognized.

Contracts are often modified to account for changes in contract specifications and requirements. The Company considers contract modifications to exist when the modification either creates new or changes the existing enforceable rights and obligations. Generally, contract modifications are for goods or services that are not distinct from the existing contract due to the significant integration of services provided in the context of the contract and are accounted for as if they were part of that existing contract.

The effect of a contract modification on the transaction price and the measure of progress for the performance obligation to which it relates, is recognized as an adjustment to revenue on a cumulative catch-up basis.

The Company's construction contracts generally contain variable consideration including liquidated damages, performance bonuses or incentives and penalties or index pricing. The variable amounts usually arise upon achievement of certain performance metrics. The Company estimates variable consideration at the most likely amount expected.

The Company believes its estimates surrounding the cost-to-cost method are reasonable based on the information that is known when the estimates are made. The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes available for each job. There were no material changes in contract estimates at the individual contract level in 2018.

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~~2017 Annual Report.

At ~~September 30, 2017,~~March 31, 2018, the Company had no outstanding interest rate hedges.

Item 4. Controls and Procedures

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 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 ~~September 30, 2017,~~March 31, 2018, 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~~2017 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, 2018	—	—		—	—
February 1 through February 28, 2018	182,424		$27.52	—	—
March 1 through March 31, 2018	—	—		—	—
Total	182,424			—	—


(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.

Exhibits Index



			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed Herewith	Form	Period Ended	Exhibit	Filing Date	File Number

+10(a)	Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 14, 2018		8-K		10.1	2/21/18	1-03480
+10(b)	Restricted Stock Unit Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 14, 2018		8-K		10.3	2/21/18	1-03480
12	Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends	X
31(a)	Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X
31(b)	Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X
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	X
95	Mine Safety Disclosures	X
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.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

+ 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.

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:	~~November 3, 2017~~May 4, 2018	BY:	/s/ Jason L. Vollmer
			Jason L. Vollmer
			Vice President, Chief Financial Officer and Treasurer


		BY:	/s/ Stephanie A. Barth
			Stephanie A. Barth
			Vice President, Chief Accounting Officer and Controller

~~Exhibit Index~~



~~Exhibit No.~~

~~+10(a)~~	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated 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)~~	Jason L. Vollmer Offer Letter, dated September 20, 2017, filed as Exhibit 10.1 to Form 8-K dated September 15, 2017, filed on September 21, 2017, in File No. 1-03480*

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

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

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

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

~~101.CAL~~	~~XBRL Taxonomy Extension Calculation Linkbase Document~~

~~101.DEF~~	~~XBRL Taxonomy Extension Definition Linkbase Document~~

~~101.LAB~~	~~XBRL Taxonomy Extension Label Linkbase Document~~

~~101.PRE~~	~~XBRL Taxonomy Extension Presentation Linkbase Document~~

* Incorporated herein by reference as indicated.
** Filed herewith.
~~+ Management contract, compensatory plan or arrangement.~~

4649



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)
Balance at beginning of period	$	(2,484	)	$	(35,604	)	$	(144	)	$	26		$	(38,206	)
Other comprehensive loss before reclassifications	—			—			(4		)	(42		)	(46		)
Amounts reclassified from accumulated other comprehensive loss	92			236			—			33			361
Net current-period other comprehensive income (loss)	92			236			(4		)	(9		)	315
Balance at end of period	$	(2,392	)	$	(35,368	)	$	(148	)	$	17		$	(37,891	)



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



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



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



	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30,	2017			2016			2017			2016
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	377		$	412
Interest cost	4,052			4,305			816			922
Expected return on assets	(5,132		)	(5,231		)	(1,160		)	(1,133		)
Amortization of prior service credit	—			—			(343		)	(343		)
Amortization of net actuarial loss	1,589			1,553			213			371
Net periodic benefit cost (credit), including amount capitalized	509			627			(97		)	229
Less amount capitalized	65			82			(95		)	(34		)
Net periodic benefit cost (credit)	$	444		$	545		$	(2	)	$	263



	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

(In thousands)

Property, plant and equipment additions in accounts payable