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 March 31, 2019

OR

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

For the transition period from _____________ to ______________

Commission file number 1-03480

MDU RESOURCES GROUP, INC.

(Exact name of registrant as specified in its charter)

Delaware		30-1133956
(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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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, a 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.

Large accelerated filer ý	Accelerated filer o
Non-accelerated filer o	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.

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, par value $1.00 per share	MDU	New York Stock Exchange

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of April 26, 2019: 198,083,324 shares.

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Index

		Page
Definitions		3
Forward-Looking Statements		5
Introduction		5
Part I -- Financial Information
Item 1	Financial Statements
	Consolidated Statements of Income -- Three Months Ended March 31, 2019 and 2018	6
	Consolidated Statements of Comprehensive Income -- Three Months Ended March 31, 2019 and 2018	7
	Consolidated Balance Sheets -- March 31, 2019 and 2018, and December 31, 2018	8
	Consolidated Statements of Equity -- Three Months Ended March 31, 2019 and 2018	9
	Consolidated Statements of Cash Flows -- Three Months Ended March 31, 2019 and 2018	10
	Notes to Consolidated Financial Statements	11
Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4	Controls and Procedures	49
Part II -- Other Information
Item 1	Legal Proceedings	50
Item 1A	Risk Factors	50
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 4	Mine Safety Disclosures	50
Item 6	Exhibits	50
Exhibits Index		51
Signatures		52

2

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Definitions

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

Abbreviation or Acronym
2018 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2018
AFUDC	Allowance for funds used during construction
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
Brazilian Transmission Lines	Company's former investment in companies owning three electric transmission lines in Brazil
BSSE	345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota
Calumet	Calumet Specialty Products Partners, L.P.
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. (formerly known as MDUR Newco), which, as the context requires, refers to the previous MDU Resources Group, Inc. prior to January 1, 2019, and the new holding company of the same name after January 1, 2019
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 prior to the closing of the Holding Company Reorganization and a public utility division of Montana-Dakota as of January 1, 2019
Holding Company Reorganization	The internal holding company reorganization completed on January 1, 2019, pursuant to the agreement and plan of merger, dated as of December 31, 2018, by and among Montana-Dakota, the Company and MDUR Newco Sub, which resulted in the Company becoming a holding company and owning all of the outstanding capital stock of Montana-Dakota
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
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

3

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MDUR Newco	MDUR Newco, Inc., a public holding company created by implementing the Holding Company Reorganization, now known as the Company
MDUR Newco Sub	MDUR Newco Sub, Inc., a direct, wholly owned subsidiary of MDUR Newco, which was merged with and into Montana-Dakota in the Holding Company Reorganization
MMcf	Million cubic feet
MMdk	Million dk
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., (formerly known as MDU Resources Group, Inc.), a public utility division of the Company prior to the closing of the Holding Company Reorganization and a direct wholly owned subsidiary of MDU Energy Capital as of January 1, 2019
MTPSC	Montana Public Service Commission
MW	Megawatt
NDPSC	North Dakota Public Service Commission
Non-GAAP	Not in accordance with GAAP
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
PRP	Potentially Responsible Party
ROD	Record of Decision
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
SSIP	System Safety and Integrity Program
TCJA	Tax Cuts and Jobs Act
Tesoro	Tesoro Refining & Marketing Company 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 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

4

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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 - 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 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 2018 Annual Report and subsequent filings with the SEC.

Introduction

The Company is a regulated energy delivery and construction materials and services business. Montana-Dakota was incorporated under the laws of the state of Delaware in 1924. The Company was incorporated under the laws of the state of Delaware in 2018. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

On January 2, 2019, the Company announced the completion of the Holding Company Reorganization, which resulted in Montana-Dakota becoming a subsidiary of the Company. The merger was conducted pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the stockholders of the constituent corporation. Immediately after consummation of the Holding Company Reorganization, the Company had, on a consolidated basis, the same assets, businesses and operations as Montana-Dakota had immediately prior to the consummation of the Holding Company Reorganization. As a result of the Holding Company Reorganization, the Company became the successor issuer to Montana-Dakota pursuant to Rule 12g-3(a) of the Exchange Act, and as a result, the Company's common stock was deemed registered under Section 12(b) of the Exchange Act.

The Company, through its wholly owned subsidiary, MDU Energy Capital, owns Montana-Dakota, Cascade and Intermountain. Montana-Dakota, Cascade and Intermountain are 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 the pipeline and midstream segment, 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, see Note 17 of the Notes to Consolidated Financial Statements.

5

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Part I -- Financial Information

Item 1. Financial Statements

MDU Resources Group, Inc.

Consolidated Statements of Income

(Unaudited)

		Three Months Ended
		March 31,
		2019			2018
		(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream		$	439,617		$	424,459
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other		651,574			551,834
Total operating revenues		1,091,191			976,293
Operating expenses:
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream		87,770			86,112
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other		615,144			514,744
Total operation and maintenance		702,914			600,856
Purchased natural gas sold		183,829			181,967
Depreciation, depletion and amortization		59,897			52,729
Taxes, other than income		54,029			48,854
Electric fuel and purchased power		26,304			22,511
Total operating expenses		1,026,973			906,917
Operating income		64,218			69,376
Other income		7,595			582
Interest expense		23,407			20,447
Income before income taxes		48,406			49,511
Income taxes		7,317			7,551
Income from continuing operations		41,089			41,960
Income (loss) from discontinued operations, net of tax (Note 10)		(163		)	477
Net income		$	40,926		$	42,437
Earnings per share - basic:
Income from continuing operations		$	.21		$	.22
Discontinued operations, net of tax		—			—
Earnings per share - basic		$	.21		$	.22
Earnings per share - diluted:
Income from continuing operations		$	.21		$	.22
Discontinued operations, net of tax		—			—
Earnings per share - diluted		$	.21		$	.22
Weighted average common shares outstanding - basic		196,401			195,304
Weighted average common shares outstanding - diluted		196,414			195,982

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

6

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MDU Resources Group, Inc.

Consolidated Statements of Comprehensive Income

(Unaudited)

		Three Months Ended
		March 31,
		2019			2018
		(In thousands)
Net income		$	40,926		$	42,437
Other comprehensive income:
Reclassification adjustment for loss on derivative instruments included in net income, net of tax of $(249) and $56 for the three months ended in 2019 and 2018, respectively		397			92
Amortization of postretirement liability losses included in net periodic benefit cost (credit), net of tax of $100 and $155 for the three months ended in 2019 and 2018, respectively		310			418
Foreign currency translation adjustment recognized during the period, net of tax of $0 and $(1) for the three months ended in 2019 and 2018, respectively		—			(2		)
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized gain (loss) on available-for-sale investments arising during the period, net of tax of $10 and $(28) for the three months ended in 2019 and 2018, respectively		39			(105		)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $7 and $7 for the three months ended in 2019 and 2018, respectively		28			30
Net unrealized gain (loss) on available-for-sale investments		67			(75		)
Other comprehensive income		774			433
Comprehensive income attributable to common stockholders		$	41,700		$	42,870

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

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MDU Resources Group, Inc.

Consolidated Balance Sheets

(Unaudited)

	March 31, 2019			March 31, 2018			December 31, 2018
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	49,721		$	58,764		$	53,948
Receivables, net	722,152			664,319			722,945
Inventories	311,535			257,792			287,309
Prepayments and other current assets	151,391			59,481			119,500
Current assets held for sale	430			458			430
Total current assets	1,235,229			1,040,814			1,184,132
Investments	144,616			138,451			138,620
Property, plant and equipment	7,502,368			6,842,967			7,397,321
Less accumulated depreciation, depletion and amortization	2,858,986			2,725,484			2,818,644
Net property, plant and equipment	4,643,382			4,117,483			4,578,677
Deferred charges and other assets:
Goodwill	679,395			631,791			664,922
Other intangible assets, net	11,680			3,465			10,815
Operating lease right-of-use assets (Note 11)	107,486			—			—
Other	455,048			412,456			408,857
Noncurrent assets held for sale	2,087			4,392			2,087
Total deferred charges and other assets	1,255,696			1,052,104			1,086,681
Total assets	$	7,278,923		$	6,348,852		$	6,988,110
Liabilities and Stockholders' Equity
Current liabilities:
Short-term borrowings	$	70,000		$	—		$	—
Long-term debt due within one year	251,846			149,199			251,854
Accounts payable	352,180			267,994			358,505
Taxes payable	55,319			57,354			41,929
Dividends payable	39,875			38,573			39,695
Accrued compensation	45,383			35,087			69,007
Current operating lease liabilities (Note 11)	30,978			—			—
Other accrued liabilities	213,541			204,328			221,059
Current liabilities held for sale	3,657			11,726			4,001
Total current liabilities	1,062,779			764,261			986,050
Long-term debt	1,946,181			1,630,343			1,856,841
Deferred credits and other liabilities:
Deferred income taxes	444,965			346,218			430,085
Noncurrent operating lease liabilities (Note 11)	76,444			—			—
Other	1,142,862			1,181,919			1,148,359
Total deferred credits and other liabilities	1,664,271			1,528,137			1,578,444
Commitments and contingencies
Stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value Shares issued - 198,316,808 at March 31, 2019, 195,843,297 at March 31, 2018 and 196,564,907 at December 31, 2018	198,317			195,843			196,565
Other paid-in capital	1,284,060			1,227,285			1,248,576
Retained earnings	1,164,509			1,051,469			1,163,602
Accumulated other comprehensive loss	(37,568		)	(44,860		)	(38,342		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)
Total stockholders' equity	2,605,692			2,426,111			2,566,775
Total liabilities and stockholders' equity	$	7,278,923		$	6,348,852		$	6,988,110

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

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MDU Resources Group, Inc.

Consolidated Statements of Equity

(Unaudited)

Three Months Ended March 31, 2019
						Other Paid-in Capital			Retained Earnings			Accumu-lated Other Compre-hensive Loss
	Common Stock														Treasury Stock
	Shares		Amount												Shares		Amount			Total
	(In thousands, except shares)
At December 31, 2018	196,564,907		$	196,565		$	1,248,576		$	1,163,602		$	(38,342	)	(538,921	)	$	(3,626	)	$	2,566,775
Net income	—		—			—			40,926			—			—		—			40,926
Other comprehensive income	—		—			—			—			774			—		—			774
Dividends declared on common stock	—		—			—			(40,019		)	—			—		—			(40,019		)
Stock-based compensation	—		—			1,617			—			—			—		—			1,617
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	246,214		246			(3,261		)	—			—			—		—			(3,015		)
Issuance of common stock	1,505,687		1,506			37,128			—			—			—		—			38,634
At March 31, 2019	198,316,808		$	198,317		$	1,284,060		$	1,164,509		$	(37,568	)	(538,921	)	$	(3,626	)	$	2,605,692

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
	(In thousands, except shares)
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	—		—			—			(38,705		)	—			—		—			(38,705		)
Stock-based compensation	—		—			1,223			—			—			—		—			1,223
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		)
At March 31, 2018	195,843,297		$	195,843		$	1,227,285		$	1,051,469		$	(44,860	)	(538,921	)	$	(3,626	)	$	2,426,111

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MDU Resources Group, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

		Three Months Ended
		March 31,
		2019			2018
		(In thousands)
Operating activities:
Net income		$	40,926		$	42,437
Income (loss) from discontinued operations, net of tax		(163		)	477
Income from continuing operations		41,089			41,960
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		59,897			52,729
Deferred income taxes		12,658			(2,068		)
Changes in current assets and liabilities, net of acquisitions:
Receivables		(2,641		)	62,711
Inventories		(21,407		)	(29,997		)
Other current assets		(31,586		)	22,506
Accounts payable		356			(31,864		)
Other current liabilities		(6,310		)	(5,115		)
Other noncurrent changes		(49,965		)	(5,302		)
Net cash provided by continuing operations		2,091			105,560
Net cash provided by (used in) discontinued operations		(507		)	231
Net cash provided by operating activities		1,584			105,791
Investing activities:
Capital expenditures		(133,839		)	(105,136		)
Acquisitions, net of cash acquired		(30,868		)	—
Net proceeds from sale or disposition of property and other		4,938			5,966
Investments		(340		)	(1,074		)
Net cash used in investing activities		(160,109		)	(100,244		)
Financing activities:
Issuance of short-term borrowings		70,000			—
Issuance of long-term debt		141,338			101,588
Repayment of long-term debt		(52,964		)	(37,047		)
Proceeds from issuance of common stock		38,634			—
Dividends paid		(39,695		)	(38,573		)
Repurchase of common stock		—			(5,020		)
Tax withholding on stock-based compensation		(3,015		)	(2,330		)
Net cash provided by financing activities		154,298			18,618
Increase (decrease) in cash and cash equivalents		(4,227		)	24,165
Cash and cash equivalents -- beginning of year		53,948			34,599
Cash and cash equivalents -- end of period		$	49,721		$	58,764

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

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MDU Resources Group, Inc.

Notes to Consolidated

Financial Statements

March 31, 2019 and 2018

(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 2018 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.

On January 2, 2019, the Company announced the completion of the Holding Company Reorganization, which resulted in Montana-Dakota becoming a subsidiary of the Company. The purpose of the reorganization was to make the public utility divisions into a subsidiary of the holding company, just as the other operating companies are wholly owned subsidiaries.

Effective January 1, 2019, the Company adopted the requirements of the ASU on leases, as further discussed in Notes 6 and 11. As such, results for reporting periods beginning January 1, 2019, 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 leases.

The assets and liabilities for the Company's discontinued operations have been classified as held for sale and the results of operations are shown in income (loss) 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 10.

Management has also evaluated the impact of events occurring after March 31, 2019, up to the date of issuance of these consolidated interim financial statements.

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 consists 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 $38.3 million, $36.3 million and $30.0 million at March 31, 2019 and 2018, and December 31, 2018, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at March 31, 2019 and 2018, and December 31, 2018, was $9.6 million, $8.2 million and $8.9 million, respectively.

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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 was included in inventories. Inventories on the Consolidated Balance Sheets were as follows:

	March 31, 2019			March 31, 2018			December 31, 2018
	(In thousands)
Aggregates held for resale	$	142,747		$	123,053		$	139,681
Asphalt oil	83,459			61,647			54,741
Materials and supplies	26,441			19,493			23,611
Merchandise for resale	25,104			16,378			22,552
Natural gas in storage (current)	11,464			10,936			22,117
Other	22,320			26,285			24,607
Total	$	311,535		$	257,792		$	287,309

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 $48.2 million, $47.8 million and $48.5 million at March 31, 2019 and 2018, and December 31, 2018, respectively.

Note 5 - Earnings per share

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

	Three Months Ended
	March 31,
	2019			2018
	(In thousands, except per share amounts)
Weighted average common shares outstanding - basic	196,401			195,304
Effect of dilutive performance share awards and restricted stock units	13			678
Weighted average common shares outstanding - diluted	196,414			195,982
Shares excluded from the calculation of diluted earnings per share	64			—
Dividends declared per common share	$	.2025		$	.1975

Note 6 - New accounting standards

Recently adopted accounting standards

ASU 2016-02 - Leases In February 2016, the FASB issued guidance regarding leases. The guidance required lessees to recognize a lease liability and a right-of-use asset on the balance sheet for operating and financing leases. The guidance remained 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 required additional disclosures, both quantitative and qualitative, related to operating and financing leases for the lessee and sales-type, direct financing and operating leases for the lessor. The Company adopted the standard on January 1, 2019.

In July 2018, the FASB issued ASU 2018-11 - Leases: Targeted Improvements, an accounting standard update to ASU 2016-02. This ASU provided an entity the option to adopt the guidance using one of two modified retrospective approaches. An entity could adopt the guidance using the modified retrospective transition approach beginning in the earliest year presented in the financial statements. This method of adoption would have required the restatement of prior periods reported and the presentation of lease disclosures under the new guidance for all periods reported. The additional transition method of adoption, introduced by ASU 2018-11, allowed entities the option to apply the guidance on the date of adoption by recognizing a cumulative effect adjustment to retained earnings during the period of adoption and did not require prior comparative periods to be restated.

The Company adopted the standard on January 1, 2019, utilizing the additional transition method of adoption applied on the date of adoption and the practical expedient that allowed the Company to not reassess whether an expired or existing contract contained a lease, the classification of leases or initial direct costs. The Company did not identify any cumulative effect

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adjustments. The Company also adopted a short-term leasing policy as the lessee where leases with a term of 12 months or less are not included on the Consolidated Balance Sheet.

As a practical expedient, a lessee may choose not to separate nonlease components from lease components and instead account for lease and nonlease components as a single lease component. The election shall be made by asset class. The Company has elected to adopt the lease/nonlease component practical expedient for all asset classes as the lessee. The Company did not elect the practical expedient to use hindsight when assessing the lease term or impairment of right-of-use assets for the existing leases on the date of adoption.

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 has adopted this practical expedient.

The Company formed a lease implementation team to review and assess existing contracts to identify and evaluate those containing leases. Additionally, the team implemented new and revised existing software to meet the reporting and disclosure requirements of the standard. The Company also assessed the impact the standard had on its processes and internal controls and identified new and updated existing internal controls and processes to ensure compliance with the new lease standard; such modifications were not deemed to be significant. During the assessment phase, the Company used various surveys, reconciliations and analytic methodologies to ensure the completeness of the lease inventory. The Company determined that most of the current operating leases were subject to the guidance and were recognized as operating lease liabilities and right-of-use assets on the Consolidated Balance Sheet upon adoption. On January 1, 2019, the Company recorded approximately $112 million to right-of-use assets and lease liabilities as a result of the initial adoption of the guidance. In addition, the Company evaluated the impact the new guidance had on lease contracts where the Company is the lessor and determined it did not have a significant impact.

ASU 2018-15 - Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract In August 2018, the FASB issued guidance on the accounting for implementation costs of a hosting arrangement that is a service contract. The guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract similar to the costs incurred to develop or obtain internal-use software and such capitalized costs to be expensed over the term of the hosting arrangement. Costs incurred during the preliminary and postimplementation stages should continue to be expensed as activities are performed. The capitalized costs are required to be presented on the balance sheet in the same line the prepayment for the fees associated with the hosting arrangement would be presented. In addition, the expense related to the capitalized implementation costs should be presented in the same line on the income statement as the fees associated with the hosting element of the arrangements. The Company adopted the guidance effective January 1, 2019, on a prospective basis. The adoption of the guidance did not have a material impact on its results of operations, financial position, cash flows, and disclosures.

Recently issued accounting standards not yet adopted

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 must be applied on a prospective basis with early adoption permitted. The Company is evaluating the guidance and does not expect it to have a material impact on its results of operations, financial position, cash flows and disclosures.

ASU 2018-13 - Changes to the Disclosure Requirements for Fair Value Measurement In August 2018, the FASB issued guidance on modifying the disclosure requirements on fair value measurements as part of the disclosure framework project. The guidance modifies, among other things, the disclosures required for Level 3 fair value measurements, including the range and weighted average of significant unobservable inputs. The guidance removes, among other things, the disclosure requirement to disclose transfers between Levels 1 and 2. The guidance will be effective for the Company on January 1, 2020, including interim periods, with early adoption permitted. Level 3 fair value measurement disclosures should be applied prospectively while all other amendments should be applied retrospectively. The Company is evaluating the effects the adoption of the new guidance will have on its disclosures.

ASU 2018-14 - Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued guidance on modifying the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans as part of the disclosure framework project. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The guidance adds, among other things, the requirement to include an explanation for significant gains and losses related to changes in benefit obligations for the

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period. The guidance removes, among other things, the disclosure requirement to disclose the amount of net periodic benefit costs to be amortized over the next fiscal year from accumulated other comprehensive income (loss) and the effects a one percentage point change in assumed health care cost trend rates will have on certain benefit components. The guidance will be effective for the Company on January 1, 2021, and must be applied on a retrospective basis with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its disclosures.

ASU 2018-18 - Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued guidance on whether certain transactions between collaborative arrangement participants should be accounted for within revenue under Topic 606 to provide for better comparability among entities. The guidance clarifies which transactions should be accounted for as revenue under Topic 606 and provides unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 regarding distinct goods or services. The guidance also specifies that transactions with a collaborative arrangement not directly related to sales to third parties may not be presented together with revenue recognized under Topic 606. The guidance will be effective for the Company on January 1, 2020, including interim periods, and must be applied retrospectively to January 1, 2018, the date in which the Company adopted Topic 606. An entity may apply the guidance to either all contracts or to only contracts that are not completed as of the date of the initial application of Topic 606. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

Note 7 - Comprehensive income (loss)

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

Three Months Ended March 31, 2019	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,161	)	$	(36,069	)	$	(112	)	$	(38,342	)
Other comprehensive income before reclassifications	—			—			39			39
Amounts reclassified from accumulated other comprehensive loss	397			310			28			735
Net current-period other comprehensive income	397			310			67			774
Balance at end of period	$	(1,764	)	$	(35,759	)	$	(45	)	$	(37,568	)

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)
Balance at beginning of period	$	(1,934	)	$	(35,163	)	$	(155	)	$	(82	)	$	(37,334	)
Other comprehensive loss before reclassifications	—			—			(2		)	(105		)	(107		)
Amounts reclassified from accumulated other comprehensive loss	92			418			—			30			540
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	$	(2,231	)	$	(42,265	)	$	(190	)	$	(174	)	$	(44,860	)

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The following amounts were reclassified out of accumulated other comprehensive loss into net income. The amounts presented in parenthesis indicate a decrease to net income on the Consolidated Statements of Income. The reclassifications were as follows:

	Three Months Ended						Location on Consolidated Statements of Income
	March 31,
	2019			2018
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income	$	(148	)	$	(148	)	Interest expense
	(249		)	56			Income taxes
	(397		)	(92		)
Amortization of postretirement liability losses included in net periodic benefit cost (credit)	(410		)	(573		)	Other income
	100			155			Income taxes
	(310		)	(418		)
Reclassification adjustment on available-for-sale investments included in net income	(35		)	(37		)	Other income
	7			7			Income taxes
	(28		)	(30		)
Total reclassifications	$	(735	)	$	(540	)

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 of these taxes at the time of sale to be remitted to governmental authorities, including sales and use taxes.

As part of the adoption of ASC 606 - Revenue from Contracts with Customers, 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 otherwise would have recognized is one year or less.

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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 17.

Three Months Ended March 31, 2019	Electric			Natural gas distribution			Pipeline and midstream			Construction materials and contracting			Construction services			Other			Total
	(In thousands)
Residential utility sales	$	36,555		$	200,609		$	—		$	—		$	—		$	—		$	237,164
Commercial utility sales	35,671			121,793			—			—			—			—			157,464
Industrial utility sales	8,884			8,611			—			—			—			—			17,495
Other utility sales	1,799			—			—			—			—			—			1,799
Natural gas transportation	—			11,570			25,058			—			—			—			36,628
Natural gas gathering	—			—			2,121			—			—			—			2,121
Natural gas storage	—			—			2,646			—			—			—			2,646
Contracting services	—			—			—			83,039			—			—			83,039
Construction materials	—			—			—			179,309			—			—			179,309
Intrasegment eliminations*	—			—			—			(35,140		)	—			—			(35,140		)
Inside specialty contracting	—			—			—			—			299,530			—			299,530
Outside specialty contracting	—			—			—			—			107,398			—			107,398
Other	9,121			3,913			2,696			—			17			7,843			23,590
Intersegment eliminations	—			—			(23,955		)	(95		)	(129		)	(7,824		)	(32,003		)
Revenues from contracts with customers	92,030			346,496			8,566			227,113			406,816			19			1,081,040
Revenues out of scope	536			(4,349		)	47			—			13,917			—			10,151
Total external operating revenues	$	92,566		$	342,147		$	8,613		$	227,113		$	420,733		$	19		$	1,091,191

*	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.

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.

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Contract balances

The timing of revenue recognition may differ from the timing of invoicing to customers. The timing of invoicing to customers does not necessarily correlate with the timing of revenues being recognized under the cost‐to‐cost method of accounting. 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 changes in contract assets and liabilities were as follows:

	March 31, 2019			December 31, 2018			Change			Location on Consolidated Balance Sheets
	(In thousands)
Contract assets	$	117,036		$	104,239		$	12,797		Receivables, net
Contract liabilities - current	(86,031		)	(93,901		)	7,870			Accounts payable
Contract liabilities - noncurrent	(30		)	(135		)	105			Deferred credits and other liabilities - other
Net contract assets	$	30,975		$	10,203		$	20,772

The Company recognized $56.4 million in revenue for the three months ended March 31, 2019, which was previously included in contract liabilities at December 31, 2018. 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 a net increase in revenues of $18.7 million and $3.1 million for the three months ended March 31, 2019 and 2018, respectively, from performance obligations satisfied in prior periods.

Note 9 - Business combinations

In March 2019, the Company acquired Viesko Redi-Mix, Inc., a provider of ready-mixed concrete in Oregon. The gross aggregate consideration for this acquisition was $32.1 million, subject to certain adjustments, which includes $1.2 million of debt assumed. The acquisition is subject to customary adjustments based on, among other things, the amount of cash, debt and working capital in the business as of the closing date. The amounts included in the Consolidated Balance Sheet for these adjustments are considered provisional until final settlement has occurred.

The purchase price adjustments for all business combinations that occurred during 2018 have been settled and the purchase price allocations are considered final; except for Sweetman Construction Company, which was acquired in October 2018. No material adjustments were made to the provisional accounting for the business combinations.

Business combinations were accounted for in accordance with ASC 805 - Business Combinations. The results of the acquired businesses have been included in the Company's construction materials and contracting segment and Consolidated Financial Statements beginning on the acquisition date. Pro forma financial amounts reflecting the effects of the business combinations are not presented, as these business combinations were not material to the Company's financial position or results of operations.

For all business combinations, the Company preliminarily allocates the purchase price of the acquisitions to the assets acquired and liabilities assumed based on their estimated fair values as of the acquisition dates and are considered provisional until final fair values are determined, or the measurement period has passed. The Company expects to record adjustments as it accumulates the information needed to estimate the fair value of assets acquired and liabilities assumed, including working capital balances, estimated fair value of identifiable intangible assets, property, plant and equipment, total consideration and goodwill. The excess of the purchase price over the aggregate fair values is recorded as goodwill. The Company calculated the fair value of the assets acquired in 2019 and 2018 using a market or cost approach (or a combination of both). Fair values for some of the assets were determined based on Level 3 inputs including estimated future cash flows, discount rates, growth rates, sales projections, retention rates and terminal values, all of which require significant management judgment and are susceptible to change. The final fair value of the net assets acquired may result in adjustments to the assets and liabilities, including goodwill, and will be made as soon as practical, but no later than one year from the respective acquisition dates. However, any subsequent measurement period adjustments are not expected to have a material impact on the Company's results of operations.

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Note 10 - Discontinued operations

The assets and liabilities of the Company's discontinued operations have been classified as held for sale and the results of operations are shown in income (loss) 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 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 reduced the Company’s risk by decreasing exposure to commodity prices.

In connection with the sale of Dakota Prairie Refining, Centennial guaranteed certain debt obligations of Dakota Prairie Refining and Tesoro agreed to indemnify Centennial for any losses and litigation expenses arising from the guarantee. On October 17, 2018, Centennial was released of any further liabilities or obligations under this guarantee.

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. In July 2018, the Company completed the sale of a majority of the remaining property, plant and equipment. 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.

Dakota Prairie Refining and Fidelity The carrying amounts of the major classes of assets and liabilities classified as held for sale on the Consolidated Balance Sheets were as follows:

	March 31, 2019			March 31, 2018			December 31, 2018
	(In thousands)
Assets
Current assets:
Receivables, net	$	430		$	458		$	430
Income taxes receivable (a)	—			1,858			—
Total current assets held for sale	430			2,316			430
Noncurrent assets:
Net property, plant and equipment	—			1,631			—
Deferred income taxes	1,926			2,637			1,926
Other	161			161			161
Total noncurrent assets held for sale	2,087			4,429			2,087
Total assets held for sale	$	2,517		$	6,745		$	2,517
Liabilities
Current liabilities:
Accounts payable	$	—		$	—		$	80
Taxes payable	1,295			10,774			1,451
Other accrued liabilities	2,362			2,810			2,470
Total current liabilities held for sale	3,657			13,584			4,001
Noncurrent liabilities:
Deferred income taxes (b)	—			37			—
Total noncurrent liabilities held for sale	—			37			—
Total liabilities held for sale	$	3,657		$	13,621		$	4,001

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

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

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The reconciliation of the major classes of income and expense constituting pretax loss from discontinued operations to the after-tax income (loss) from discontinued operations on the Consolidated Statements of Income was as follows:

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Operating revenues	$	30		$	66
Operating expenses	245			174
Operating loss	(215		)	(108		)
Other income	—			12
Interest expense	—			575
Loss from discontinued operations before income taxes	(215		)	(671		)
Income taxes	(52		)	(1,148		)
Income (loss) from discontinued operations	$	(163	)	$	477

Note 11 - Leases

Most of the leases the Company enters into are for equipment, buildings, easements and vehicles as part of their ongoing operations. The Company also leases certain equipment to third parties through its utility and construction services segments. The Company determines if an arrangement contains a lease at inception of a contract and accounts for all leases in accordance with ASC 842 - Leases. For more information on the adoption of ASC 842, see Note 6.

The recognition of leases requires the Company to make estimates and assumptions that affect the lease classification and the assets and liabilities recorded. The accuracy of lease assets and liabilities reported on the Consolidated Financial Statements depends on, among other things, management's estimates of interest rates used to discount the lease assets and liabilities to its present value, as well as the lease terms based on the unique facts and circumstances of each lease.

Lessee accounting

The leases the Company has entered into as part of their ongoing operations are considered operating leases and are recognized on the balance sheet as right-of-use assets, current lease liabilities and, if applicable, noncurrent lease liabilities. Lease liabilities and their corresponding right-of-use assets are recorded based on the present value of lease payments over the expected lease term. The Company determines the lease term based on the non-cancelable and cancelable periods in each contract. The non-cancelable period consists of the term of the contract that is legally enforceable and cannot be canceled by either party without incurring a significant penalty. The cancelable period is determined by various factors that are based on who has the right to cancel a contract. If only the lessor has the right to cancel the contract, the Company will assume the contract will continue. If the lessee is the only party that has the right to cancel the contract, the Company looks to asset, entity and market-based factors. If both the lessor and the lessee have the right to cancel the contract, the Company assumes the contract will not continue.

Generally, the leases for vehicles and equipment have a term of five years or less and buildings and easements have a longer term of up to 35 years or more. To date, the Company does not have any residual value guarantee amounts probable of being owed to a lessor, financing leases or material agreements with related parties.

The Company has elected to recognize leases with an original lease term of 12 months or less in income on a straight-line basis over the term of the lease and not recognize a corresponding right-of-use asset or lease liability. Lease costs are included in operation and maintenance expense on the Company's Consolidated Statements of Income. The discount rate used to calculate the present value of the lease liabilities is based upon the implied rate within each contract. If the rate is unknown or cannot be determined, the Company uses an incremental borrowing rate which is determined by the length of the contract, asset class and the Company's borrowing rates as of the commencement date of the contract.

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The following table provides information on the Company's operating leases for the three months ended:

	March 31,
	2019
	(Dollars in thousands)
Weighted average remaining lease term	2.63 years
Weighted average discount rate	4.51		%
Cash paid for amounts included in the measurement of lease liabilities	$	11,467
Lease costs:
Operating lease cost	$	11,521
Variable lease cost	399
Short-term lease cost	17,238
Total lease costs	$	29,158

As of March 31, 2019, the Company had operating leases that had not yet commenced and will create approximately $7.5 million of additional right-of-use assets and lease liabilities in future periods. The reconciliation of the future undiscounted cash flows to the operating lease liabilities presented on the Company's Consolidated Balance Sheet is as follows:

	March 31, 2019
	(In thousands)
Remainder of 2019	$	26,655
2020	25,743
2021	18,503
2022	11,886
2023	6,723
Thereafter	43,401
Total	132,911
Less discount	25,489
Total operating lease liabilities	$	107,422

As previously disclosed in the 2018 Annual Report, the undiscounted annual minimum lease payments due under the Company's leases following the previous lease accounting standard as of December 31, 2018, were as follows:

	2019			2020			2021			2022			2023			Thereafter
	(In thousands)
Operating leases	$	37,740		$	26,255		$	17,868		$	11,647		$	7,278		$	49,098

Lessor accounting

The Company leases certain equipment to third parties which are considered operating leases. The Company recognized revenue from operating leases of $14.0 million for the three months ended March 31, 2019.

The majority of the Company's operating leases are short-term leases of less than 12 months. At March 31, 2019, the Company had $11.3 million of lease receivables with a majority due within 12 months.

Note 12 - Goodwill and other intangible assets

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

Three Months Ended March 31, 2019	Balance at January 1, 2019			Goodwill Acquired During  the Year			Balance at March 31, 2019
	(In thousands)
Natural gas distribution	$	345,736		$	—		$	345,736
Construction materials and contracting	209,421			14,473			223,894
Construction services	109,765			—			109,765
Total	$	664,922		$	14,473		$	679,395

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Three Months Ended March 31, 2018	Balance at January 1, 2018			Goodwill Acquired During  the Year			Balance at March 31, 2018
	(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, 2018	Balance at January 1, 2018			Goodwill Acquired During  the Year			Balance at December 31, 2018
	(In thousands)
Natural gas distribution	$	345,736		$	—		$	345,736
Construction materials and contracting	176,290			33,131			209,421
Construction services	109,765			—			109,765
Total	$	631,791		$	33,131		$	664,922

During 2019 and 2018, the Company completed one and four business combinations, respectively, and the results of the acquired businesses have been included in the Company's construction materials and contracting segment. These business combinations increased the construction materials and contracting segment's goodwill balance at March 31, 2019 and December 31, 2018, as noted in the previous tables. As a result of the business combinations, other intangible assets increased $1.5 million at March 31, 2019, compared to December 31, 2018. For more information related to business combinations, see Note 9.

Other amortizable intangible assets were as follows:

	March 31, 2019			March 31, 2018			December 31, 2018
	(In thousands)
Customer relationships	$	14,471		$	14,668		$	22,720
Less accumulated amortization	5,156			13,007			13,535
	9,315			1,661			9,185
Noncompete agreements	3,179			2,430			2,605
Less accumulated amortization	1,730			1,842			1,956
	1,449			588			649
Other	6,458			6,458			6,458
Less accumulated amortization	5,542			5,242			5,477
	916			1,216			981
Total	$	11,680		$	3,465		$	10,815

Amortization expense for amortizable intangible assets for the three months ended March 31, 2019 and 2018, was $600,000 and $400,000, respectively. Estimated amortization expense for identifiable intangible assets as of March 31, 2019, was:

	Remainder of 2019			2020			2021			2022			2023			Thereafter
	(In thousands)
Amortization expense	$	1,403		$	1,632		$	1,242		$	1,219		$	1,237		$	4,947

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Note 13 - Regulatory assets and liabilities

The following table summarizes the individual components of unamortized regulatory assets and liabilities:

	Estimated Recovery Period	*	March 31, 2019			December 31, 2018
			(In thousands)
Regulatory assets:
Pension and postretirement benefits (a)	(e)		$	165,879		$	165,898
Natural gas costs recoverable through rate adjustments (a) (b)	Up to 3 years		91,465			42,652
Asset retirement obligations (a)	Over plant lives		63,633			60,097
Cost recovery mechanisms (a) (b)	Up to 4 years		17,835			17,948
Manufactured gas plant site remediation (a)	-		17,111			17,068
Taxes recoverable from customers (a)	Over plant lives		11,858			11,946
Plant to be retired (a)	-		6,691			—
Conservation programs (b)	Up to 1 year		6,094			7,494
Long-term debt refinancing costs (a)	Up to 19 years		4,746			4,898
Costs related to identifying generation development (a)	Up to 8 years		2,394			2,508
Other (a) (b)	Up to 20 years		5,827			9,608
Total regulatory assets			393,533			340,117
Regulatory liabilities:
Taxes refundable to customers (c) (d)			267,777			277,833
Plant removal and decommissioning costs (c) (d)			173,911			173,143
Natural gas costs refundable through rate adjustments (d)			29,739			29,995
Pension and postretirement benefits (c)			12,991			15,264
Other (c) (d)			33,976			25,197
Total regulatory liabilities			518,394			521,432
Net regulatory position			$	(124,861	)	$	(181,315	)

*	Estimated recovery period for regulatory assets currently being recovered in rates charged to customers.

(a)	Included in deferred charges and other assets - other on the Consolidated Balance Sheets.

(b)	Included in prepayments and other current assets on the Consolidated Balance Sheets.

(c)	Included in deferred credits and other liabilities - other on the Consolidated Balance Sheets.

(d)	Included in other accrued liabilities on the Consolidated Balance Sheets.

(e)	Recovered as expense is incurred or cash contributions are made.

The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. As of March 31, 2019 and December 31, 2018, approximately $279.4 million and $313.5 million, respectively, of regulatory assets were not earning a rate of return.

During the first quarter of 2019 and the fourth quarter of 2018, the Company experienced increased natural gas costs in certain jurisdictions where it supplies natural gas. The Company has recorded these natural gas costs as regulatory assets as they will be recovered from customers, as discussed in Note 19.

In February 2019, the Company announced that it intends to retire three aging coal-fired electric generation units within the next three years. The Company has accelerated the depreciation related to these facilities in property, plant and equipment and has recorded the difference between the accelerated depreciation, in accordance with GAAP, and the depreciation approved for rate-making purposes as regulatory assets. The Company expects to recover the plant to be retired in future rates.

If, for any reason, the Company's regulated businesses cease to meet the criteria for application of regulatory accounting for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income or accumulated other comprehensive income (loss) in the period in which the discontinuance of regulatory accounting occurs.

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Note 14 - 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 $80.2 million, $76.9 million and $73.8 million, at March 31, 2019 and 2018, and December 31, 2018, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized gain on these investments was $6.4 million for the three months ended March 31, 2019. The net unrealized loss on these investments was $500,000 for the three months ended March 31, 2018. The change in fair value, which is considered part of the cost of the plan, is classified in other income on the Consolidated Statements of Income.

The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities. The available-for-sale securities 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 loss. Details of available-for-sale securities were as follows:

March 31, 2019	Cost			Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	10,679		$	31		$	88		$	10,622
U.S. Treasury securities	179			—			—			179
Total	$	10,858		$	31		$	88		$	10,801

March 31, 2018	Cost			Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	10,282		$	4		$	223		$	10,063
U.S. Treasury securities	466			—			1			465
Total	$	10,748		$	4		$	224		$	10,528

December 31, 2018	Cost			Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	10,473		$	21		$	162		$	10,332
U.S. Treasury securities	179			—			—			179
Total	$	10,652		$	21		$	162		$	10,511

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 three months ended March 31, 2019 and 2018, there were no transfers between Levels 1 and 2.

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

	Fair Value Measurements at March 31, 2019, 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, 2019
	(In thousands)
Assets:
Money market funds	$	—		$	10,540		$	—		$	10,540
Insurance contract*	—			80,243			—			80,243
Available-for-sale securities:
Mortgage-backed securities	—			10,622			—			10,622
U.S. Treasury securities	—			179			—			179
Total assets measured at fair value	$	—		$	101,584		$	—		$	101,584

*	The insurance contract invests approximately 51 percent in fixed-income investments, 22 percent in common stock of large-cap companies, 12 percent in common stock of mid-cap companies, 11 percent in common stock of small-cap companies, 3 percent in target date investments and 1 percent in cash equivalents.

	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 March 31, 2018
	(In thousands)
Assets:
Money market funds	$	—		$	9,085		$	—		$	9,085
Insurance contract*	—			76,941			—			76,941
Available-for-sale securities:
Mortgage-backed securities	—			10,063			—			10,063
U.S. Treasury securities	—			465			—			465
Total assets measured at fair value	$	—		$	96,554		$	—		$	96,554

*	The insurance contract invests approximately 49 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, 3 percent in target date investments and 2 percent in cash equivalents.

	Fair Value Measurements at December 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 December 31, 2018
	(In thousands)
Assets:
Money market funds	$	—		$	10,799		$	—		$	10,799
Insurance contract*	—			73,838			—			73,838
Available-for-sale securities:
Mortgage-backed securities	—			10,332			—			10,332
U.S. Treasury securities	—			179			—			179
Total assets measured at fair value	$	—		$	95,148		$	—		$	95,148

*	The insurance contract invests approximately 53 percent in fixed-income investments, 21 percent in common stock of large-cap companies, 11 percent in common stock of mid-cap companies, 10 percent in common stock of small-cap companies, 3 percent in target date investments and 2 percent in cash equivalents.

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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 March 31, 2019	$	2,198,027		$	2,263,305
Long-term debt at March 31, 2018	$	1,779,542		$	1,854,350
Long-term debt at December 31, 2018	$	2,108,695		$	2,183,819

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

Note 15 - Debt

Certain debt instruments of the Company's subsidiaries contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the subsidiary companies must be in compliance with the applicable covenants and certain other conditions all of which the subsidiaries, as applicable, were in compliance with at March 31, 2019. In the event the Company's subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.

Montana-Dakota'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, Montana-Dakota 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.

Short-term debt

Cascade On January 18, 2019, Cascade entered into a $30.0 million term loan agreement with a variable interest rate and a due date of June 28, 2019; this agreement has been classified as short-term debt. On March 22, 2019, Cascade entered into a $40.0 million term loan agreement with a variable interest rate and a due date of December 31, 2019; this agreement has been classified as short-term debt.

Long-term debt

Long-term Debt Outstanding Long-term debt outstanding was as follows:

	Weighted Average Interest Rate at March 31, 2019		March 31, 2019			December 31, 2018
			(In thousands)
Senior Notes due on dates ranging from July 1, 2019 to January 15, 2055	4.57	%	$	1,381,000		$	1,381,000
Commercial paper supported by revolving credit agreements	2.97	%	473,900			338,100
Term Loan Agreements due on dates ranging from October 17, 2019 to September 3, 2032	2.75	%	209,800			209,800
Credit agreements due on April 24, 2020	4.42	%	62,875			110,100
Medium-Term Notes due on dates ranging from September 1, 2020 to March 16, 2029	6.68	%	50,000			50,000
Other notes due on dates ranging from July 1, 2019 to November 30, 2038	5.00	%	26,251			25,229
Less unamortized debt issuance costs			5,410			5,207
Less discount			389			327
Total long-term debt			2,198,027			2,108,695
Less current maturities			251,846			251,854
Net long-term debt			$	1,946,181		$	1,856,841

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Schedule of Debt Maturities Long-term debt maturities, which excludes unamortized debt issuance costs and discount, as of March 31, 2019, were as follows:

	Remainder of 2019			2020			2021			2022			2023			Thereafter
	(In thousands)
Long-term debt maturities	$	251,846		$	78,801		$	431,930		$	147,434		$	120,239		$	1,173,576

Note 16 - Cash flow information

Cash expenditures for interest and income taxes were as follows:

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Interest, net*	$	19,067		$	17,910
Income taxes paid (refunded), net**	$	29		$	(1,056	)

*	AFUDC - borrowed was $556,000 and $382,000 for the three months ended March 31, 2019 and 2018, respectively.

**	Income taxes paid, net of discontinued operations, were $132,000 and $1.7 million for the three months ended March 31, 2019 and 2018, respectively.

Noncash investing and financing transactions were as follows:

	March 31, 2019			March 31, 2018			December 31, 2018
	(In thousands)
Right-of-use assets obtained in exchange for new operating lease liabilities	$	2,731		$	—		$	—
Property, plant and equipment additions in accounts payable	$	27,655		$	16,829		$	42,355
Debt assumed in connection with a business combination	$	1,163		$	—		$	—
Issuance of common stock in connection with a business combination	$	—		$	—		$	18,186

Note 17 - 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.

The construction materials and contracting segment mines, processes and sells construction aggregates (crushed stone, sand and gravel); produces and sells asphalt mix; and supplies 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 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 include design, construction and maintenance of electrical and communication wiring and infrastructure, fire suppression systems, and mechanical piping and services. This segment also constructs and

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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 self-insured layers of the insured Company's general liability, automobile liability, pollution liability and other coverages. Centennial Capital also owns certain real and personal property. In addition, the Other category includes certain assets, liabilities and tax adjustments of the holding company primarily associated with the corporate functions and certain general and administrative costs (reflected in operation and maintenance expense) and interest expense which were previously allocated to the refining business and Fidelity that do not meet the criteria for income (loss) from discontinued operations. The Other category also includes Centennial Resources' former investment in Brazil.

Discontinued operations include the results and supporting activities of Dakota Prairie Refining and Fidelity other than certain general and administrative costs and interest expense as described above. For more information on discontinued operations, see Note 10.

The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2018 Annual Report. Information on the Company's segments was as follows:

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
External operating revenues:
Regulated operations:
Electric	$	92,566		$	87,404
Natural gas distribution	342,147			332,664
Pipeline and midstream	4,904			4,391
	439,617			424,459
Nonregulated operations:
Pipeline and midstream	3,709			4,442
Construction materials and contracting	227,113			213,284
Construction services	420,733			334,050
Other	19			58
	651,574			551,834
Total external operating revenues	$	1,091,191		$	976,293
Intersegment operating revenues:
Regulated operations:
Electric	$	—		$	—
Natural gas distribution	—			—
Pipeline and midstream	23,922			21,735
	23,922			21,735
Nonregulated operations:
Pipeline and midstream	33			24
Construction materials and contracting	95			101
Construction services	129			11
Other	7,824			2,638
	8,081			2,774
Intersegment eliminations	(32,003		)	(24,509		)
Total intersegment operating revenues	$	—		$	—

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	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Operating income (loss):
Electric	$	17,987		$	18,154
Natural gas distribution	50,317			48,540
Pipeline and midstream	9,904			8,168
Construction materials and contracting	(41,580		)	(26,309		)
Construction services	27,465			20,634
Other	125			189
Total operating income	$	64,218		$	69,376
Net income:
Regulated operations:
Electric	$	15,505		$	13,084
Natural gas distribution	36,500			32,623
Pipeline and midstream	7,004			5,459
	59,009			51,166
Nonregulated operations:
Pipeline and midstream	(163		)	(179		)
Construction materials and contracting	(34,449		)	(23,521		)
Construction services	20,024			15,090
Other	(3,332		)	(596		)
	(17,920		)	(9,206		)
Income from continuing operations	41,089			41,960
Income (loss) from discontinued operations, net of tax	(163		)	477
Net income	$	40,926		$	42,437

Note 18 - 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 March 31,	2019			2018			2019			2018
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	344		$	407
Interest cost	3,773			3,807			780			778
Expected return on assets	(5,120		)	(4,998		)	(1,220		)	(1,167		)
Amortization of prior service credit	—			—			(252		)	(349		)
Amortization of net actuarial loss	1,355			1,782			—			238
Net periodic benefit cost (credit), including amount capitalized	8			591			(348		)	(93		)
Less amount capitalized	—			—			31			40
Net periodic benefit cost (credit)	$	8		$	591		$	(379	)	$	(133	)

The components of net periodic benefit cost (credit), other than the service cost component, are included in other income on the Consolidated Statements of Income. The service cost component is included in operation and maintenance expense on the Consolidated Statements of Income.

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Nonqualified defined benefit plans

In addition to the qualified defined benefit pension plans reflected in the table at the beginning of this note, 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 million and $1.1 million for the three months ended March 31, 2019 and 2018, respectively. The components of net periodic benefit cost for these plans, which does not contain any service costs, are included in other income on the Consolidated Statements of Income.

Note 19 - 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.

MNPUC

On December 29, 2017, the MNPUC issued a notice of investigation related to tax changes with the enactment of the TCJA. On January 19, 2018, the MNPUC issued a notice of request for information, commission planning meeting and subsequent comment period. Pursuant to the notice, Great Plains provided preliminary impacts of the TCJA on January 30, 2018. On March 2, 2018, Great Plains submitted its initial filing addressing the impacts of the TCJA advocating existing rates are reasonable and a reduction in rates is not warranted. On August 9, 2018, the MNPUC ruled that Great Plains reduce rates to reflect TCJA impacts and to also provide a one-time refund that captures the TCJA impacts from January 1, 2018 through the implementation date of new rates. On December 5, 2018, the MNPUC issued an order requiring Great Plains reduce its rates by $400,000 on an annual basis and provide a one-time refund of approximately $400,000, as previously mentioned. The required compliance filing was submitted to the MNPUC on January 4, 2019. On April 18, 2019, the MNPUC approved the decrease in rates effective May 1, 2019, as well as the TCJA refund, to be issued within 120 days of the implementation of new rates, for the period from January 1, 2018 through April 30, 2019.

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. Montana-Dakota submitted the general electric rate case on September 28, 2018, as discussed below. On November 30, 2018, Montana-Dakota and interveners of the case submitted a stipulation and settlement agreement reflecting a one-time refund of approximately $1.5 million to account for all TCJA related impacts from January 1, 2018 through the date new rates are effective in the rate case noted below. A hearing was held on December 4, 2018, and the MTPSC issued an order accepting the stipulation and settlement agreement on December 21, 2018, requiring a one-time bill credit to occur in April 2019. The TCJA refund was credited to customers' bills on March 29, 2019.

On September 28, 2018, Montana-Dakota filed an application with the MTPSC for an electric rate increase of approximately $11.9 million annually or approximately 18.9 percent above current rates. The requested increase is primarily to recover investments in facilities to enhance safety and reliability and the depreciation and taxes associated with the increase in investment. The increase was partially offset by tax savings related to the TCJA. On March 7, 2019, the MTPSC issued an interim order authorizing an interim increase of $7.9 million or approximately 12.8 percent, subject to refund, to be effective with service rendered on or after April 1, 2019. On April 24, 2019, Montana-Dakota submitted a settlement agreement reflecting a $9.0 million annual increase to be implemented in the first twelve months following the date of approval and an additional $300,000 annual increase to be implemented beginning twelve months after the date of approval. 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 also introduced a 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 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 approximately $3.6 million. On July 19, 2018, a settlement was filed reflecting a revised annual revenue increase of approximately $2.5 million or approximately 2.3 percent. The proposed adjustment mechanism to fund the SSIP was not included in the settlement and was to be decided on separately by the NDPSC. On September 26, 2018, the NDPSC issued an order approving the settlement as filed but did not approve the SSIP

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recovery mechanism. On October 5, 2018, Montana-Dakota submitted a compliance filing, which included a plan for the one-time refund to be available March 1, 2019, for the interim amount to be refunded to customers. The NDPSC approved the compliance rates that were effective with service rendered on and after December 1, 2018. The interim refund of approximately $600,000 was credited to customers' bills on March 1, 2019.

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. On August 10, 2018, a settlement agreement was filed requesting a decrease in rates of approximately $8.4 million. On September 26, 2018, the NDPSC issued an order approving the settlement along with requiring an additional adjustment to the rates to return 100 percent of the tax-effective 2018 excess deferred income taxes. On October 10, 2018, Montana-Dakota submitted a compliance filing, which included a refund plan for the interim amount to be refunded to customers. On November 20, 2018, the NDPSC approved the compliance rates which were effective with service rendered on and after December 1, 2018. The NDPSC also approved a one-time refund of approximately $7.9 million to be credited to customers' bills by March 15, 2019, based on 4.7 percent of the revenues collected between January 1, 2018 through November 30, 2018. The TCJA refund was credited to customers' bills on March 15, 2019.

On October 19, 2018, Great Plains and the NDPSC advocacy staff filed a settlement agreement to resolve all outstanding issues in the NDPSC's investigation into the TCJA and a revenue neutral tariff filing submitted by Great Plains. The settlement agreement provides for miscellaneous tariff changes and a reduction in annual revenues of $168,000. On January 9, 2019, the NDPSC issued an order approving the settlement agreement and a refund requirement for the period from January 1, 2018 through the month preceding the effective date of the rate change. On January 23, 2019, the NDPSC approved the compliance rates which were effective February 1, 2019, along with the refund plan that provides for approximately $200,000 in refunds that were credited to customers' bills on April 12, 2019.

OPUC

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. The deferral request was renewed on December 28, 2018. This matter is pending before the OPUC.

On May 31, 2018, Cascade filed a general rate case with the OPUC requesting an overall increase to Cascade's natural gas rates of approximately $2.3 million or 3.5 percent on an annual basis, which incorporates the impact of the TCJA. On January 22, 2019, Cascade filed a stipulation with the OPUC for an annual increase in revenues of $1.7 million with a $500,000 reduction for excess deferred income taxes, for a net increase of $1.2 million. On March 14, 2019, the OPUC approved the settlement with rates effective April 1, 2019.

SDPUC

On December 29, 2017, the SDPUC issued an order initiating the investigation into the effects of the TCJA. The order required Montana-Dakota 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. On May 4, 2018 and June 2, 2018, Montana-Dakota submitted detailed plans to address the TCJA impacts on the natural gas and electric utilities, respectively, to the SDPUC staff. On September 28, 2018, a settlement agreement was submitted to the SDPUC reflecting a proposal to refund approximately $600,000 to electric customers and approximately $1.4 million to natural gas customers. These refunds reflect the impact of the TCJA on 2018. On October 23, 2018, an order was issued by the SDPUC approving the settlement agreement with the refunds being credited to customers' bills beginning on February 15, 2019. On December 3, 2018, Montana-Dakota submitted proposed rate changes to reflect 2018 pro forma results and the TCJA impacts. On December 28, 2018, the SDPUC approved an annual decrease in revenues of approximately $300,000 for the natural gas operations and approximately $100,000 for the electric operations. The decrease in revenues was effective January 1, 2019. The TCJA refund for both electric and natural gas was credited to customers' bills on February 15, 2019.

WUTC

On March 28, 2019, the WUTC approved an increase to Cascade's natural gas rates through an out-of-period purchased gas adjustment surcharge. The increase of approximately $48.0 million reflects unrecovered purchased gas costs from October 2018 through the end of January 2019 as a result of the rupture of the Enbridge pipeline in Canada on October 8, 2019, causing increased natural gas costs. The WUTC approved this amount, including interest, to be collected over three years beginning April 1, 2019.

On March 29, 2019, Cascade filed a general rate case with the WUTC requesting an increase in annual revenue of $12.7 million or approximately 5.5 percent. This matter is pending before the WUTC. The WUTC has eleven months to process the request and issue an order.

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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 approximately $1.1 million annually or approximately 4.2 percent. Revised electric rates reflecting this reduction were submitted to the WYPSC on June 13, 2018. Compliance rates were submitted to the WYPSC on April 4, 2019. On April 8, 2019, the WYPSC approved the Company's requested decrease in electric rates and required a refund to customers for the period from January 1, 2018 through the date prior to the implementation of the rates within 90 days of the effective date of the new rates. This matter is pending before the WYPSC.

On March 30, 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

On July 18, 2018, the FERC issued a final rule on Rate Changes Relating to Federal Income Tax Rate reductions resulting from the TCJA which requires natural gas pipeline companies to make a one-time informational filing to evaluate the impact of the lower corporate income tax rate and select one of four options presented by the FERC to address the impact. 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 no later than May 1, 2019. On October 31, 2018, the Company filed a rate case with the FERC. Due to the timing of the rate case filing, the Company was exempt from the one-time informational filing required by the FERC’s final rule. On November 30, 2018, the FERC issued an order accepting and suspending tariff records, subject to refund, and establishing hearing procedures. The FERC order accepted the Company's rate case filing and suspended the associated tariff records subject to refund and the outcome of a hearing. The Company filed a motion on April 30, 2019, to place the suspended tariff records into effect May 1, 2019. This matter is pending before the FERC.

Note 20 - 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 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 has accrued liabilities of $32.4 million, $37.4 million and $30.4 million, which have not been discounted, including liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at March 31, 2019 and 2018, and December 31, 2018, respectively. This includes amounts that have been accrued for matters discussed in 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 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.

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 the Willamette River site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site where the EPA wants responsible parties to share in the costs of cleanup. 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. Investigative costs are indicated to be in excess of $100 million. Remediation 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 was also notified 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. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

At this time, Knife River - Northwest does not believe it is a responsible party and 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.

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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. LWG has 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 accruals related to these claims are reflected in regulatory assets. For more information, see Note 13.

The first claim is for contamination at a site in Eugene, Oregon, which was received in 1995. The Oregon DEQ released an 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 $400,000 has been incurred. Cascade and other PRPs will share in the cleanup costs with Cascade expecting to pay approximately 50 percent of the remediation and maintenance costs. Cascade has an accrual balance of $1.5 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, December 1, 2017 and December 1, 2018.

The second claim is for contamination at 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 $3.3 million has been incurred. Cascade has accrued $4.3 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 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. Other PRPs reached an agreed order and work plan with the Washington DOE for completion of a remedial investigation and feasibility study for the site. A feasibility study prepared for one of the PRPs in March 2018 identifies five cleanup action alternatives for the site with estimated costs ranging from $8.0 million to $20.4 million with a selected preferred alternative having an estimated total cost of $9.3 million. The other PRPs will develop a cleanup action plan and, after public review of the cleanup action plan, develop design documents. 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 recorded an accrual for this site for an amount that is not material.

Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for certain of the 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.

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Guarantees

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

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, insurance deductibles and loss limits, and certain other guarantees. At March 31, 2019, the fixed maximum amounts guaranteed under these agreements aggregated $182.5 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate to $83.0 million in 2019; $92.5 million in 2020; $500,000 in 2021; $500,000 in 2022; $500,000 in 2023; $1.5 million thereafter; and $4.0 million, which has no scheduled maturity date. There were no amounts outstanding under the above guarantees at March 31, 2019. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At March 31, 2019, the fixed maximum amounts guaranteed under these letters of credit aggregated $28.6 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate to $6.4 million in 2019 and $22.2 million in 2020. There were no amounts outstanding under the above letters of credit at March 31, 2019. In the event of default under these letter of credit obligations, the subsidiary guaranteeing the letter of credit would be obligated for reimbursement of payments made under the 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 were reflected on the Consolidated Balance Sheet at March 31, 2019.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At March 31, 2019, approximately $903.9 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 March 31, 2019, 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 $37.9 million.

Note 21 - Subsequent Events

On April 4, 2019, Centennial entered into a $150.0 million senior note purchase agreement with interest rates between 4.53 percent and 4.73 percent and maturities between April 4, 2029 and April 4, 2034.

On April 12, 2019, Centennial entered into a $50.0 million term loan agreement with a variable interest rate, which matures on April 11, 2020.

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

On January 2, 2019, the Company announced the completion of the Holding Company Reorganization, which resulted in Montana-Dakota becoming a subsidiary of the Company. The merger was conducted pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the stockholders of the constituent corporation. Immediately after consummation of the Holding Company Reorganization, the Company had, on a consolidated basis, the same assets, businesses and operations as Montana-Dakota had immediately prior to the consummation of the Holding Company Reorganization. As a result of the Holding Company Reorganization, the Company became the successor issuer to Montana-Dakota pursuant to Rule 12g-3(a) of the Exchange Act, and as a result, the Company's common stock was deemed registered under Section 12(b) of the Exchange Act.

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 customers, including commercial, industrial and governmental industries, and provides construction materials through aggregate mining and marketing of related products, such as ready-mixed 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 business 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 growth opportunities and strategic acquisitions. The Company is focused on a disciplined approach to the acquisition of well-managed companies and properties.

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

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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,
	2019			2018
	(In millions, except per share amounts)
Electric	$	15.5		$	13.1
Natural gas distribution	36.5			32.6
Pipeline and midstream	6.8			5.3
Construction materials and contracting	(34.4		)	(23.5		)
Construction services	20.0			15.1
Other	(3.3		)	(.7		)
Income from continuing operations	41.1			41.9
Income (loss) from discontinued operations, net of tax	(.2		)	.5
Net income	$	40.9		$	42.4
Earnings per share - basic:
Income from continuing operations	$	.21		$	.22
Discontinued operations, net of tax	—			—
Earnings per share - basic	$	.21		$	.22
Earnings per share - diluted:
Income from continuing operations	$	.21		$	.22
Discontinued operations, net of tax	—			—
Earnings per share - diluted	$	.21		$	.22

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 The Company recognized consolidated earnings of $40.9 million for the quarter ended March 31, 2019, compared to $42.4 million for the same period in 2018.

Negatively impacting the Company's earnings were seasonal losses associated with businesses acquired since the first quarter of 2018 along with lower margins due to less favorable weather in certain regions at the construction materials and contracting business. Partially offsetting these decreases were increased earnings at the natural gas distribution business, primarily resulting from increased retail sales volumes of 12 percent relating to all customer classes and increased earnings at the construction services business due to increased customer demand and workloads for both inside and outside specialty contracting.

A discussion of key financial data from the Company's business segments follows.

Business Segment Financial and Operating Data

Following are key financial and operating data for each of the Company's business segments. Also included are highlights on key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters of the Company's business segments. Many of these highlighted points are "forward-looking statements." For more information, see 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 2018 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 17 of the Notes to Consolidated Financial Statements.

Electric and Natural Gas Distribution

Strategy and challenges The electric and natural gas distribution segments provide electric and natural gas distribution services to customers, as discussed in Note 17. 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, environmentally friendly, reliable and competitively priced energy and related services to customers. The Company continues to monitor opportunities for these segments to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation, transmission and distribution and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity 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, weather, competitive factors in the energy industry, population growth and economic conditions in the segments' service areas.

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The electric and natural gas distribution segments are subject to extensive regulation in the jurisdictions where they conduct operations with respect to costs, timely recovery of investments and permitted returns on investment, as well as certain operational, system integrity and environmental regulations. To assist in the reduction of regulatory lag with the increase in investments, tracking mechanisms have been implemented in certain jurisdictions. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas, as well as increase costs to produce electricity and natural gas. Although the current administration has slowed environmental regulations, the segments continue to invest in facility upgrades to be in compliance with the existing and future regulations.

Tariff increases on steel and aluminum materials could negatively affect the segments' construction projects and maintenance work. The Company continues to monitor the impact of tariffs on raw material costs. The natural gas distribution segment is also facing increased lead times on delivery of certain raw materials used in pipeline projects. In addition to the effect of tariffs, long lead times are attributable to increased demand for steel products from pipeline companies as they respond to the United States Department of Transportation Pipeline System Safety and Integrity Plan. The Company continues to monitor the material lead times and is working with manufacturers to proactively order such materials to help mitigate the risk of delays due to extended lead times.

The ability to grow through acquisitions is subject to significant competition and acquisition premiums. In addition, the ability of 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 likely necessitate increases in electric energy prices.

Revenues are impacted by both customer growth and 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 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. Natural gas 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.

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

	Three Months Ended
	March 31,
	2019			2018
	(Dollars in millions, where applicable)
Operating revenues	$	92.6		$	87.4
Electric fuel and purchased power	26.3			22.5
Taxes, other than income	.2			.2
Adjusted gross margin	66.1			64.7
Operating expenses:
Operation and maintenance	30.2			30.1
Depreciation, depletion and amortization	13.7			12.6
Taxes, other than income	4.2			3.8
Total operating expenses	48.1			46.5
Operating income	18.0			18.2
Other income	2.1			.3
Interest expense	6.4			6.6
Income before income taxes	13.7			11.9
Income taxes	(1.8		)	(1.2		)
Net income	$	15.5		$	13.1
Retail sales (million kWh):
Residential	379.6			374.0
Commercial	406.2			402.3
Industrial	139.5			142.3
Other	21.9			22.7
	947.2			941.3
Average cost of electric fuel and purchased power per kWh	$	.025		$	.022

Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross margin attributable to the electric segment, see the Non-GAAP Financial Measures section later in this Item.

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 Electric earnings increased $2.4 million (19 percent) as a result of:

Adjusted gross margin: Increase of $1.4 million, primarily due to increased revenues associated with regulatory mechanisms which now include the completed Thunder Spirit Wind farm expansion, partially offset by lower rate realization in certain jurisdictions due to the impacts of tax reform on rates. Also contributing to the increase was higher retail sales volumes for residential and commercial customers.

Operation and maintenance: Comparable to the same period in prior year.

Depreciation, depletion and amortization: Increase of $1.1 million as a result of increased property, plant and equipment balances.

Taxes, other than income: Increase of $400,000, primarily from higher property taxes in certain jurisdictions.

Other income: Increase of $1.8 million, primarily the result of higher returns on investments.

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

Income taxes: Increase in income tax benefits of $600,000 resulting from increased production tax credits and other permanent tax benefits, partially offset by higher income taxes due to higher income before income taxes.

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

	Three Months Ended
	March 31,
	2019			2018
	(Dollars in millions, where applicable)
Operating revenues	$	342.1		$	332.6
Purchased natural gas sold	207.8			203.7
Taxes, other than income	12.1			12.2
Adjusted gross margin	122.2			116.7
Operating expenses:
Operation and maintenance	46.3			44.8
Depreciation, depletion and amortization	19.4			17.7
Taxes, other than income	6.2			5.7
Total operating expenses	71.9			68.2
Operating income	50.3			48.5
Other income	2.9			.5
Interest expense	8.4			7.6
Income before income taxes	44.8			41.4
Income taxes	8.3			8.8
Net income	$	36.5		$	32.6
Volumes (MMdk)
Retail sales:
Residential	31.4			28.1
Commercial	20.9			18.6
Industrial	1.6			1.4
	53.9			48.1
Transportation sales:
Commercial	.8			.8
Industrial	40.6			36.8
	41.4			37.6
Total throughput	95.3			85.7
Average cost of natural gas, including transportation, per dk	$	3.85		$	4.23

Adjusted gross margin is a non-GAAP financial measure. For additional information and reconciliation of the non-GAAP adjusted gross margin attributable to the natural gas distribution segment, see the Non-GAAP Financial Measures section later in this Item.

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 Natural gas distribution earnings increased $3.9 million (12 percent) as a result of:

Adjusted gross margin: Increase of $5.5 million resulting from the increase in retail sales volumes of 12 percent related to all customer classes due to colder weather offset in part by weather normalization and conservation adjustments in certain jurisdictions. The adjusted gross margins were also positively impacted by higher rate realization due to higher conservation revenue, which offsets the conservation expense in operation and maintenance expense, partially offset by the impacts of tax reform on rates.

Operation and maintenance: Increase of $1.5 million, primarily conservation expenses being recovered in revenue.

Depreciation, depletion and amortization: Increase of $1.7 million, primarily as a result of increased property, plant and equipment balances.

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

Other income: Increase of $2.4 million, largely resulting from higher returns on investments and increased interest income related to higher gas costs to be collected from customers.

Interest expense: Increase of $800,000, largely resulting from increased debt balances to finance higher gas costs to be collected from customers.

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Income taxes: Decrease of $500,000 resulting from increased permanent tax benefits, partially offset by higher income taxes due to higher income before income taxes.

Outlook The Company expects these segments will grow rate base by approximately 5 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 and replacement electric generation and transmission and natural gas systems.

In June 2016, the Company, along with a partner, began construction on the BSSE project. The Company's capital investment for this project was approximately $125 million. In February 2019, the project was placed into service.

In February 2019, the Company announced that it intends to retire three aging coal-fired electric generation units within the next three years, resulting from the Company's analysis showing that the plants are no longer expected to be cost competitive for customers. The retirements are expected to be in late 2020 for Lewis & Clark Station in Sidney, Montana, and in late 2021 for units 1 and 2 at Heskett Station in Mandan, North Dakota. In addition, the Company announced that it intends to construct a new simple-cycle natural gas combustion turbine peaking unit at the existing plant site in Mandan, North Dakota. The simple-cycle will be included in the Company's next integrated resource plan.

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 19.

The Company currently does not have any labor contracts in negotiations at the electric and natural gas distribution segments.

Pipeline and Midstream

Strategy and challenges The pipeline and midstream segment provides natural gas transportation, gathering and underground storage services, as discussed in Note 17. The segment focuses on utilizing its extensive expertise in the design, construction and operation of energy infrastructure and related services to increase market share and profitability through optimization of existing operations, organic growth and investments in energy-related assets within or in close proximity to its current operating areas. The segment focuses on the continual safety and reliability of its systems, which entails building and maintaining safe natural gas pipelines and facilities. The segment continues to evaluate growth opportunities including the expansion of existing storage, gathering and transmission facilities; incremental pipeline projects, which expand pipeline capacity; and expansion of energy-related services leveraging on its 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.

Tariff increases on steel and aluminum materials could negatively affect the segment's construction projects and maintenance work. The Company continues to monitor the impact of tariffs on raw material costs. The segment experiences extended lead times on raw materials that are critical to the segment's construction and maintenance work. Long lead times on materials could delay maintenance work and project construction potentially causing lost revenues and/or increased costs. The Company continues to proactively monitor and plan for the material lead times, as well as work with manufacturers and suppliers to help mitigate the risk of delays due to extended lead times.

The pipeline and midstream segment is subject to extensive regulation including certain operational, system integrity and environmental regulations, as well as various permit terms and operational compliance conditions. The segment is charged with the ongoing process of reviewing existing permits and 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 to remain competitive and 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 can also have a negative impact on the segment.

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

	Three Months Ended
	March 31,
	2019			2018
	(Dollars in millions)
Operating revenues	$	32.6		$	30.6
Operating expenses:
Operation and maintenance	14.6			15.0
Depreciation, depletion and amortization	4.8			4.3
Taxes, other than income	3.3			3.1
Total operating expenses	22.7			22.4
Operating income	9.9			8.2
Other income	.6			—
Interest expense	1.8			1.2
Income before income taxes	8.7			7.0
Income taxes	1.9			1.7
Net income	$	6.8		$	5.3
Transportation volumes (MMdk)	98.7			78.3
Natural gas gathering volumes (MMdk)	3.4			3.7
Customer natural gas storage balance (MMdk):
Beginning of period	13.9			22.4
Net withdrawal	(11.6		)	(14.7		)
End of period	2.3			7.7

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 Pipeline and midstream earnings increased $1.5 million (30 percent) as a result of:

Revenues: Increase of $2.0 million, largely attributable to increased volumes of natural gas transported through its system as a result of organic growth projects completed in 2018, which were partially offset by decreased storage related revenue due to narrow natural gas pricing spreads, as discussed in the Outlook section.

Operation and maintenance: Decrease of $400,000, primarily from lower payroll-related costs.

Depreciation, depletion and amortization: Increase of $500,000, primarily increased property, plant and equipment balances, largely the result of organic growth projects that have been placed into service.

Taxes, other than income: Comparable to the same period in prior year.

Other income: Increase of $600,000, primarily the result of higher returns on investments.

Interest expense: Increase of $600,000, largely resulting from higher debt balances.

Income taxes: Comparable to the same period in the prior year.

Outlook The Company has continued to experience the effects of natural gas production at record levels, which has provided opportunities for organic growth projects and increased demand. The completion of organic growth projects has contributed to the Company transporting increasing volumes of natural gas through its system. Additionally, the record levels of natural gas supply have moderated the need for storage services and put downward pressure on natural gas prices and minimized pricing volatility. Both natural gas production levels and pressure on natural gas prices are expected to continue 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.

In 2019, the Company plans to complete two additional natural gas pipeline growth projects, the Demicks Lake project and Line Section 22 Expansion project. The Company has signed long-term commitment contracts supporting both projects. The Demicks Lake project, which includes approximately 14 miles of 20-inch pipe and is designed to increase capacity by 175 MMcf per day, is located in McKenzie County, North Dakota. Construction began in April of 2019 with an in-service date in the fall. The Line Section 22 Expansion project in the Billings, Montana, area is also scheduled to begin construction in the second quarter of 2019 with an expected in-service date later in the year. The project is designed to increase capacity by 22.5 MMcf per day to serve incremental demand in Billings, Montana. Additionally, the Company signed a long-term commitment contract supporting additional natural gas pipeline growth in McKenzie County, North Dakota. This Demicks Lake Expansion project is designed to

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increase capacity by 175 MMcf per day. Construction is expected to begin in the third quarter of 2019, with an expected in-service date in early 2020.

In January 2019, the Company announced plans to construct approximately 67 miles of new pipeline, compression and ancillary facilities to transport natural gas from core Bakken production areas near Tioga, North Dakota, and extend to a new interconnection point in McKenzie County, North Dakota. This North Bakken Expansion project, as designed, would provide 200 MMcf per day of natural gas transportation capacity. Construction is expected to begin in early 2021 with an estimated completion date late in 2021, which is dependent on regulatory and environmental permitting and finalization of transportation agreements with customers. The estimated cost of the project is approximately $220 million.

In November 2018, the Company completed construction and placed into service its Valley Expansion project, a 38-mile pipeline that delivers natural gas supply to eastern North Dakota and far western Minnesota. The project, which is designed to transport 40 MMcf of natural gas per day, is under the jurisdiction of the FERC.

In September 2018, the Company completed construction and placed into service the Line Section 27 Expansion project in the Bakken area of northwestern North Dakota. The project includes approximately 13 miles of new pipeline and associated facilities and increases capacity by over 200 MMcf per day. The project brings total capacity of Line Section 27 to over 600 MMcf per day.

The Company currently does not have any labor contracts in negotiations at the pipeline and midstream segment.

Construction Materials and Contracting

Strategy and challenges The construction materials and contracting segment provides an integrated set of construction services, as discussed in Note 17. The segment focuses on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthening the long-term, strategic aggregate reserve position through available purchase and/or lease opportunities; enhancing profitability through cost containment, margin discipline and vertical integration of the segment's operations; development and recruitment of talented employees; and continued growth through organic and acquisition opportunities.

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 segment's expertise. The Company's acquisition activity supports this strategy.

As one of the country's largest sand and gravel producers, the segment continues to strategically manage its approximately 1.0 billion tons of 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 Company's aggregate reserves are naturally declining and as a result, the Company seeks acquisition opportunities to replace the reserves. The Company's aggregate reserves increased by approximately 50 million tons in 2018 primarily due to acquisition activity.

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 segment's operating margins. The segment is also subject to volatility in the cost of raw materials such as diesel fuel, gasoline, liquid asphalt, cement and steel. Although it is difficult to determine the split between inflation and supply/demand increases, diesel fuel costs remained fairly stable for the first three months of 2019, while asphalt oil costs have trended higher in 2019 compared to 2018. 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 control costs, as well as find and train a skilled workforce to meet the needs of increasing demand and seasonal work.

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

	Three Months Ended
	March 31,
	2019			2018
	(Dollars in millions)
Operating revenues	$	227.2		$	213.4
Cost of sales:
Operation and maintenance	220.8			198.9
Depreciation, depletion and amortization	16.8			13.0
Taxes, other than income	8.4			7.8
Total cost of sales	246.0			219.7
Gross margin	(18.8		)	(6.3		)
Selling, general and administrative expense:
Operation and maintenance	20.0			17.6
Depreciation, depletion and amortization	.8			.6
Taxes, other than income	2.0			1.8
Total selling, general and administrative expense	22.8			20.0
Operating loss	(41.6		)	(26.3		)
Other income (expense)	1.3			(.6		)
Interest expense	5.3			3.7
Loss before income taxes	(45.6		)	(30.6		)
Income taxes	(11.2		)	(7.1		)
Net loss	$	(34.4	)	$	(23.5	)
Sales (000's):
Aggregates (tons)	3,871			3,847
Asphalt (tons)	166			226
Ready-mixed concrete (cubic yards)	608			572

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 Construction materials and contracting's seasonal loss increased $10.9 million (46 percent) as a result of:

Revenues: Increase of $13.8 million, primarily the result of recent acquisitions and increased agency work.

Gross margin: Decrease of $12.5 million largely resulting from seasonal negative gross margins associated with the businesses acquired since the first quarter of 2018 and decreased materials margins, largely attributable to less favorable weather in certain regions. Partially offsetting the decrease was increased construction margins as a result of favorable job performance.

Selling, general and administrative expense: Increase of $2.8 million, primarily payroll-related costs and higher office expense, largely related to the businesses acquired since the first quarter of 2018.

Other income: Increase of $1.9 million, primarily the result of higher returns on investments.

Interest expense: Increase of $1.6 million, largely resulting from higher debt balances as a result of recent acquisitions.

Income taxes: Increase in income tax benefits of $4.1 million, largely the result of an increased loss before income taxes.

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 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 IBISWorld Incorporated Industry Report issued in May 2018 for sand and gravel mining in the United States projects a 1.8 percent annual growth rate through 2023. The report also states the demand for clay and refractory materials is projected to continue deteriorating in several downstream manufacturing industries, but this decline will be offset by stronger demand from the housing market and buoyant

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demand from the highway and bridge construction market. The Company believes stronger demand in the housing markets along with continued demand from the highway and bridge construction markets should provide a stable demand for construction materials and contracting products and services in the near future.

In February 2019, the Company purchased additional aggregate deposits in Texas, which will augment existing company operations and enhance its ability to sell aggregates to third parties in the coming years. In March 2019, the Company acquired Viesko Redi-Mix, Inc., a ready-mixed concrete supplier headquartered near Salem, Oregon, which is expected to be accretive to the segment's earnings in 2019. The Company continues to evaluate additional acquisition opportunities. For more information on the Company's business combinations, see Note 9.

The construction materials and contracting segment's backlog at March 31, 2019, was $943.4 million, up from $691.9 million at March 31, 2018. The increase in backlog was primarily attributable to increased agency work and bidding opportunities in nearly every region. The Company expects to complete a significant amount of backlog at March 31, 2019, during the next 12 months.

One of the labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business Properties - General in the 2018 Annual Report, has been ratified. The remaining four labor contracts remain in negotiations.

Construction Services

Strategy and challenges The construction services segment provides inside and outside specialty contracting, as discussed in Note 17. The construction services segment focuses on providing a superior return on investment 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.

The construction services segment faces challenges in the highly competitive markets in which it operates. Competitive pricing environments, project delays, changes in management's estimates of variable consideration and the effects from restrictive regulatory requirements have negatively impacted revenues and margins in the past and could affect revenues and margins in the future. Additionally, margins may be negatively impacted on a quarterly basis due to adverse weather conditions, as well as timing of 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 programs. Due to these and other factors, the Company believes customer demand for labor resources will continue to increase, possibly surpassing the supply of industry resources.

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

	Three Months Ended
	March 31,
	2019			2018
	(In millions)
Operating revenues	$	420.9		$	334.1
Cost of sales:
Operation and maintenance	351.6			278.0
Depreciation, depletion and amortization	3.7			3.5
Taxes, other than income	15.9			12.8
Total cost of sales	371.2			294.3
Gross margin	49.7			39.8
Selling, general and administrative expense:
Operation and maintenance	20.3			17.3
Depreciation, depletion and amortization	.3			.4
Taxes, other than income	1.6			1.4
Total selling, general and administrative expense	22.2			19.1
Operating income	27.5			20.7
Other income	.6			.2
Interest expense	1.2			.9
Income before income taxes	26.9			20.0
Income taxes	6.9			4.9
Net income	$	20.0		$	15.1

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 Construction services earnings increased $4.9 million (33 percent) as a result of:

Revenues: Increase of $86.8 million, largely resulting from higher inside specialty contracting workloads from greater customer demand for hospitality and high-tech projects. Also contributing to the increase was higher outside specialty contracting demand for utility projects, as well as higher outside equipment sales and rentals.

Gross margin: Increase of $9.9 million, largely resulting from higher inside specialty contracting workloads from greater customer demand for hospitality and high-tech projects. Also contributing to the increase was higher outside specialty contracting demand for utility projects, as well as higher outside equipment sales and rentals. The increase in operation and maintenance is a direct result of the increased customer demand and workloads.

Selling, general and administrative expense: Increase of $3.1 million, primarily payroll-related costs, as well as increased bad debt expense and office expense.

Other income: Comparable to the same period in prior year.

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

Income taxes: Increase of $2.0 million, largely due to an increase in income before income taxes.

Outlook The Company continues to expect long-term growth in the electric transmission and distribution market, although the timing of large bids and subsequent construction is likely to be highly variable from year to year. The Company believes several small and medium-sized transmission and distribution projects will be available for bid in 2019.

The Company expects bidding activity to remain strong for both outside and inside specialty construction companies in 2019. 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 segment had backlog at March 31, 2019, of $1.0 billion, up from $674.7 million at March 31, 2018. The increase in backlog was largely attributable to the new project opportunities that the Company continues to see across its diverse operations, particularly in inside specialty electrical and mechanical contracting for the hospitality and gaming, high-tech, mission critical and public entities. The Company's outside power, communications and natural gas specialty operations also have a high volume of work. Additionally, the Company continues to evaluate potential acquisition opportunities that would be accretive to the Company and grow the Company's backlog.

The Company currently does not have any labor contracts in negotiations at the construction services segment.

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Other

	Three Months Ended
	March 31,
	2019			2018
	(In millions)
Operating revenues	$	7.8		$	2.7
Operating expenses:
Operation and maintenance	7.2			2.0
Depreciation, depletion and amortization	.4			.6
Taxes, other than income	.1			—
Total operating expenses	7.7			2.6
Operating income	.1			.1
Other income	.2			.4
Interest expense	.4			.8
Loss before income taxes	(.1		)	(.3		)
Income taxes	3.2			.4
Net loss	$	(3.3	)	$	(.7	)

Three Months Ended March 31, 2019, Compared to Three Months Ended March 31, 2018 The net loss for Other was negatively impacted in the first quarter of 2019 as a result of income tax adjustments. Also included in Other was insurance activity at the Company's captive insurer which impacted both operating revenues and operation and maintenance expense. 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 are also included in Other.

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 related to these items were as follows:

	Three Months Ended
	March 31,
	2019			2018
	(In millions)
Intersegment transactions:
Operating revenues	$	32.0		$	24.5
Operation and maintenance	8.1			2.8
Purchased natural gas sold	23.9			21.7

For more information on intersegment eliminations, see Note 17.

Liquidity and Capital Commitments

At March 31, 2019, the Company had cash and cash equivalents of $49.7 million and available borrowing capacity of $296.0 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; the issuance of long-term 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. Cash flows provided by operating activities in the first three months of 2019 decreased $104.2 million from the comparable period in 2018. The decrease in cash flows provided by operating activities was largely driven by an increase in accounts receivable as a result of higher revenues and the slower collection of accounts receivable balances at the construction services business as compared to the prior period. Also contributing to the decrease in operating activities was the increase in natural gas purchases that include the effects of colder weather, higher gas costs and the timing of collection of such balances from customers at the natural gas distribution business.

Investing activities Cash flows used in investing activities in the first three months of 2019 was $160.1 million compared to $100.2 million in the first three months of 2018. The increase in cash used in investing activities was primarily related to acquisition activity and asset purchases at the construction materials and contracting business.

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Financing activities Cash flows provided by financing activities in the first three months of 2019 was $154.3 million compared to $18.6 million in the first three months of 2018. The increase in cash provided by financing activities was largely due to increased debt issuance from an increase in commercial paper balances used to finance the acquisition and asset purchase activity at the construction materials and contracting business and increased short-term borrowings as a result of higher natural gas costs at the natural gas distribution business, as previously discussed. During the first three months of 2019, the Company also issued common stock for net proceeds of $38.6 million under its "at-the-market" offering and 401(k) plan.

Defined benefit pension plans

There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the 2018 Annual Report. For more information, see Note 18 and Part II, Item 7 in the 2018 Annual Report.

Capital expenditures

Capital expenditures for the first three months of 2019 were $150.4 million, which includes the completed aggregate deposit purchase and business combination at the construction materials and contracting business, as compared to $93.0 million in the first three months of 2018. Capital expenditures allocated to the Company's business segments are estimated to be approximately $644.1 million for 2019. The Company has included in the estimated capital expenditures for 2019 the completed purchase of additional aggregate deposits, the completed business combination of a ready-mixed concrete supplier, the Demicks Lake project, the Line Section 22 Expansion project and the Demicks Lake Expansion project, as previously discussed in Business Segment Financial and Operating Data.

Estimated capital expenditures for 2019 also include system upgrades; service extensions; routine equipment maintenance and replacements; buildings, land and building improvements; pipeline projects; power generation and transmission opportunities, including certain costs for additional electric generating capacity; environmental upgrades; and other growth opportunities.

The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimate previously discussed. It is anticipated that all of the funds required for capital expenditures for 2019 will be met from various sources, including internally generated funds; the Company's credit facilities, as described later; issuance of long-term debt; and issuance of equity securities.

Capital resources

Certain debt instruments of the Company's subsidiaries contain restrictive and financial covenants and cross-default provisions. In order to borrow under the respective credit agreements, the subsidiary companies must be in compliance with the applicable covenants and certain other conditions, all of which the subsidiaries, as applicable, were in compliance with at March 31, 2019. In the event the 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 in the 2018 Annual Report.

The following table summarizes the outstanding revolving credit facilities of the Company's subsidiaries at March 31, 2019:

Company		Facility		Facility Limit				Amount Outstanding				Letters of Credit				Expiration Date
				(In millions)
Montana-Dakota Utilities Co.		Commercial paper/Revolving credit agreement	(a)	$	175.0			$	42.9		(b)	$	—			6/8/23
Cascade Natural Gas Corporation		Revolving credit agreement		$	75.0		(c)	$	31.7			$	2.2		(d)	4/24/20
Intermountain Gas Company		Revolving credit agreement		$	85.0		(e)	$	31.2			$	—			4/24/20
Centennial Energy Holdings, Inc.		Commercial paper/Revolving credit agreement	(f)	$	500.0			$	431.0		(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 Montana-Dakota 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 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 subsidiary companies do not

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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.

Total equity as a percent of total capitalization was 53 percent, 58 percent and 55 percent at March 31, 2019 and 2018, and December 31, 2018, 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.

The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any public offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder. The Company's board of directors currently has authorized the issuance and sale of up to an aggregate of $1.0 billion worth of such securities. The Company's board of directors reviews this authorization on a periodic basis and the aggregate amount of securities authorized may be increased in the future.

On February 22, 2019, the Company entered into a Distribution Agreement with J.P. Morgan Securities LLC and MUFG Securities Americas Inc., as sales agents, with respect to the issuance and sale of up to 10.0 million shares of the Company's common stock in connection with an “at-the-market” offering. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement. Proceeds from the sale of shares of common stock under the agreement have been and are expected to be used for general corporate purposes, which may include, among other things, working capital, capital expenditures, debt repayment and the financing of acquisitions.

The Company issued 1.4 million shares of common stock during the first quarter of 2019 pursuant to the “at-the-market” offering, receiving net proceeds of $35.9 million. The Company paid commissions to the sales agents of approximately $363,000 in connection with the sales of common stock under the "at-the-market" offering during the first quarter of 2019. The net proceeds were used for capital expenditures and acquisitions. As of March 31, 2019, the Company had remaining capacity to issue up to 8.6 million additional shares of common stock under the "at-the-market" offering program.

Off balance sheet arrangements

As of March 31, 2019, 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 estimated interest payments, operating leases, purchase commitments, asset retirement obligations, uncertain tax positions and minimum funding requirements for its defined benefit plans for 2019 from those reported in the 2018 Annual Report.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2018 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 long-lived assets and goodwill; fair values of acquired assets and liabilities under the acquisition method of accounting; tax provisions; revenue recognized using the cost-to-cost measure of progress for contracts; and actuarially determined benefit costs. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 2018 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2018 Annual Report.

Non-GAAP Financial Measures

The Business Segment Financial and Operating Data 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 useful supplemental financial measure for investors’ understanding of the segments' operating performance. This non-GAAP financial measure should not be considered as an alternative to, or more meaningful than, GAAP financial measures such as operating income (loss) or net income (loss). The Company's non-GAAP financial measure, adjusted gross margin, is not standardized; therefore, it may not be possible to compare this financial measure with other companies’ gross margin measures having the same or similar names.

In addition to operating revenues and operating expenses, management also uses the non-GAAP financial 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 and natural gas distribution segments is calculated by adding back adjustments to operating income (loss).

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These add-back adjustments include: operation and maintenance expense; depreciation, depletion and amortization expense; and certain taxes, other than income.

Adjusted gross margin includes operating revenues less cost of electric fuel and purchased power, purchased natural gas sold and certain taxes, other than income. These taxes, other than income, included as a reduction to adjusted gross margin relate to revenue taxes. These segments pass on to their customers the increases and decreases in the wholesale cost of 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, which are passed back to customers, fluctuate with revenues as they are calculated as a percentage of revenues. For these reasons, period over period, the segments' operating income (loss) is generally not impacted. The Company's management believes the adjusted gross margin is a useful supplemental financial 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 following information reconciles operating income to adjusted gross margin for the electric segment.

	Three Months Ended
	March 31,
	2019			2018
	(In millions)
Operating income	$	18.0		$	18.2
Adjustments:
Operating expenses:
Operation and maintenance	30.2			30.1
Depreciation, depletion and amortization	13.7			12.6
Taxes, other than income	4.2			3.8
Total adjustments	48.1			46.5
Adjusted gross margin	$	66.1		$	64.7

The following information reconciles operating income to adjusted gross margin for the natural gas distribution segment.

	Three Months Ended
	March 31,
	2019			2018
	(In millions)
Operating income	$	50.3		$	48.5
Adjustments:
Operating expenses:
Operation and maintenance	46.3			44.8
Depreciation, depletion and amortization	19.4			17.7
Taxes, other than income	6.2			5.7
Total adjustments	71.9			68.2
Adjusted gross margin	$	122.2		$	116.7

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 2018 Annual Report.

At March 31, 2019, the Company had no outstanding interest rate hedges.

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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 three months ended March 31, 2019, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

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Part II -- Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings required by this item, see Note 20, which is incorporated herein by reference.

Item 1A. Risk Factors

Please refer to the Company's risk factors that are disclosed in Part I, Item 1A - Risk Factors in the 2018 Annual Report that could be materially harmful to the Company's business, prospects, financial condition or financial results if they occur. There were no material changes to the Company's risk factors provided in Part I, Item 1A - Risk Factors in the 2018 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, 2019	—		—		—		—
February 1 through February 28, 2019	114,869		$26.25		—		—
March 1 through March 31, 2019	—		—		—		—
Total	114,869				—		—

(1)	Represents shares of common stock withheld by the Company to pay taxes 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 signature page to this report.

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Exhibits Index

			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed Herewith	Form	Period Ended	Exhibit	Filing Date	File Number
2(a)	Agreement and Plan of Merger, dated December 31, 2018, by and among MDU Resources Group, Inc., MDUR Newco, Inc. MDU Newco Sub, Inc.		8-K		2(a)	1/2/19	1-03480
3(a)	Certificate of Merger, dated December 31, 2018		8-K		3(a)	1/2/19	1-03480
3(b)	Amended and Restated Certificate of Incorporation of MDU Resources Group, Inc.		8-K		3(a)	1/2/19	1-03480
3(c)	Amended and Restated Bylaws of MDU Resources Group, Inc.		8-K		3.1	2/15/19	1-03480
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

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.

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Signatures

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

		MDU RESOURCES GROUP, INC.
DATE:	May 3, 2019	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

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