MDU Resources - 10-Q quarterly report FY2017 Q2

MDU Resources - 10-Q quarterly report FY2017 Q2

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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 June 30, 2017

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

For the transition period from _____________ to ______________

Commission file number 1-03480

MDU RESOURCES GROUP, INC.

(Exact name of registrant as specified in its charter)



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

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

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

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

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



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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 28, 2017: 195,304,376 shares.

Index



		Page

Definitions		3

Forward-Looking Statements		5

Introduction		5

Part I -- Financial Information

Item 1	Financial Statements
	Consolidated Statements of Income -- Three and Six Months Ended June 30, 2017 and 2016	6

	Consolidated Statements of Comprehensive Income -- Three and Six Months Ended June 30, 2017 and 2016	7

	Consolidated Balance Sheets -- June 30, 2017 and 2016, and December 31, 2016	8

	Consolidated Statements of Cash Flows -- Six Months Ended June 30, 2017 and 2016	9

	Notes to Consolidated Financial Statements	10

Item 2	Management's Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3	Quantitative and Qualitative Disclosures About Market Risk	44

Item 4	Controls and Procedures	44

Part II -- Other Information

Item 1	Legal Proceedings	44

Item 1A	Risk Factors	44

Item 4	Mine Safety Disclosures	44

Item 5	Other Information	44

Item 6	Exhibits	44

Signatures		45

Exhibit Index		46

Exhibits

Definitions

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



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



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

Forward-Looking Statements

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

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

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

Introduction

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

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

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

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

Part I -- Financial Information

Item 1. Financial Statements

MDU Resources Group, Inc.

Consolidated Statements of Income

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and regulated pipeline and midstream	$	225,485		$	206,052		$	659,100		$	591,918
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	842,154			837,896			1,346,465			1,312,245
Total operating revenues	1,067,639			1,043,948			2,005,565			1,904,163
Operating expenses:
Electric fuel and purchased power	16,752			15,914			38,638			37,925
Purchased natural gas sold	57,668			47,439			250,617			208,474
Operation and maintenance:
Electric, natural gas distribution and regulated pipeline and midstream	77,273			77,078			156,013			151,703
Nonregulated pipeline and midstream, construction materials and contracting, construction services and other	743,656			722,742			1,222,132			1,165,243
Depreciation, depletion and amortization	51,658			54,248			102,983			109,132
Taxes, other than income	40,953			37,562			88,391			80,736
Total operating expenses	987,960			954,983			1,858,774			1,753,213
Operating income	79,679			88,965			146,791			150,950
Other income	782			872			1,798			1,921
Interest expense	20,766			22,219			41,068			45,087
Income before income taxes	59,695			67,618			107,521			107,784
Income taxes	15,290			21,320			27,478			29,620
Income from continuing operations	44,405			46,298			80,043			78,164
Loss from discontinued operations, net of tax (Note 8)	(3,190		)	(276,102		)	(1,504		)	(294,138		)
Net income (loss)	41,215			(229,804		)	78,539			(215,974		)
Loss from discontinued operations attributable to noncontrolling interest (Note 8)	—			(120,651		)	—			(131,691		)
Loss on redemption of preferred stocks	600			—			600			—
Dividends declared on preferred stocks	—			171			171			343
Earnings (loss) on common stock	$	40,615		$	(109,324	)	$	77,768		$	(84,626	)
Earnings (loss) per common share - basic:
Earnings before discontinued operations	$	.22		$	.24		$	.41		$	.40
Discontinued operations attributable to the Company, net of tax	(.01		)	(.80		)	(.01		)	(.83		)
Earnings (loss) per common share - basic	$	.21		$	(.56	)	$	.40		$	(.43	)
Earnings (loss) per common share - diluted:
Earnings before discontinued operations	$	.22		$	.24		$	.40		$	.40
Discontinued operations attributable to the Company, net of tax	(.01		)	(.80		)	—			(.83		)
Earnings (loss) per common share - diluted	$	.21		$	(.56	)	$	.40		$	(.43	)
Dividends declared per common share	$	.1925		$	.1875		$	.3850		$	.3750
Weighted average common shares outstanding - basic	195,304			195,304			195,304			195,294
Weighted average common shares outstanding - diluted	195,973			195,699			195,993			195,678

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

MDU Resources Group, Inc.

Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands)
Net income (loss)	$	41,215		$	(229,804	)	$	78,539		$	(215,974	)
Other comprehensive income (loss):
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $56 and $56 for the three months ended and $112 and $114 for the six months ended in 2017 and 2016, respectively	92			91			183			183
Postretirement liability adjustment:
Amortization of postretirement liability (gains) losses included in net periodic benefit cost (credit), net of tax of $190 and $150 for the three months ended and $406 and $(819) for the six months ended in 2017 and 2016, respectively	312			248			669			(1,347		)
Reclassification of postretirement liability adjustment from regulatory asset, net of tax of $0 and $0 for the three months ended and $(725) and $0 for the six months ended in 2017 and 2016, respectively	—			—			(917		)	—
Postretirement liability adjustment	312			248			(248		)	(1,347		)
Foreign currency translation adjustment recognized during the period, net of tax of $(9) and $19 for the three months ended and $(3) and $33 for the six months ended in 2017 and 2016, respectively	(15		)	31			(6		)	56
Net unrealized gain on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(13) and $(16) for the three months ended and $(28) and $(10) for the six months ended in 2017 and 2016, respectively	(24		)	(30		)	(51		)	(19		)
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $17 and $19 for the three months ended and $36 and $37 for the six months ended in 2017 and 2016, respectively	31			36			66			69
Net unrealized gain on available-for-sale investments	7			6			15			50
Other comprehensive income (loss)	396			376			(56		)	(1,058		)
Comprehensive income (loss)	41,611			(229,428		)	78,483			(217,032		)
Comprehensive loss from discontinued operations attributable to noncontrolling interest	—			(120,651		)	—			(131,691		)
Comprehensive income (loss) attributable to common stockholders	$	41,611		$	(108,777	)	$	78,483		$	(85,341	)

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

MDU Resources Group, Inc.

Consolidated Balance Sheets

(Unaudited)



	June 30, 2017			June 30, 2016			December 31, 2016
(In thousands, except shares and per share amounts)
Assets
Current assets:
Cash and cash equivalents	$	40,048		$	85,117		$	46,107
Receivables, net	661,771			637,166			630,243
Inventories	249,870			265,849			238,273
Prepayments and other current assets	63,953			50,309			48,461
Current assets held for sale	328			37,625			14,391
Total current assets	1,015,970			1,076,066			977,475
Investments	131,726			124,531			125,866
Property, plant and equipment	6,591,382			6,526,563			6,510,229
Less accumulated depreciation, depletion and amortization	2,638,098			2,551,941			2,578,902
Net property, plant and equipment	3,953,284			3,974,622			3,931,327
Deferred charges and other assets:
Goodwill	631,791			641,527			631,791
Other intangible assets, net	4,785			7,160			5,925
Other	416,759			360,520			415,419
Noncurrent assets held for sale	76,183			167,100			196,664
Total deferred charges and other assets	1,129,518			1,176,307			1,249,799
Total assets	$	6,230,498		$	6,351,526		$	6,284,467
Liabilities and Stockholders' Equity
Current liabilities:
Long-term debt due within one year	$	83,499		$	58,598		$	43,598
Accounts payable	279,211			275,791			279,962
Taxes payable	55,037			45,749			48,164
Dividends payable	37,596			36,791			37,767
Accrued compensation	52,951			56,390			65,867
Other accrued liabilities	181,030			196,701			184,377
Current liabilities held for sale	4,481			28,237			9,924
Total current liabilities	693,805			698,257			669,659
Long-term debt	1,677,977			1,928,709			1,746,561
Deferred credits and other liabilities:
Deferred income taxes	668,239			666,601			668,226
Other	887,525			820,349			883,777
Total deferred credits and other liabilities	1,555,764			1,486,950			1,552,003
Commitments and contingencies
Stockholders' equity:
Preferred stocks	—			15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value Shares issued - 195,843,297 at June 30, 2017 and 2016 and December 31, 2016	195,843			195,843			195,843
Other paid-in capital	1,231,892			1,230,342			1,232,478
Retained earnings	914,632			838,257			912,282
Accumulated other comprehensive loss	(35,789		)	(38,206		)	(35,733		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,302,952			2,222,610			2,301,244
Total stockholders' equity	2,302,952			2,237,610			2,316,244
Total liabilities and stockholders' equity	$	6,230,498		$	6,351,526		$	6,284,467

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

MDU Resources Group, Inc.

Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended
	June 30,
	2017			2016
	(In thousands)
Operating activities:
Net income (loss)	$	78,539		$	(215,974	)
Loss from discontinued operations, net of tax	(1,504		)	(294,138		)
Income from continuing operations	80,043			78,164
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	102,983			109,132
Deferred income taxes	(5,293		)	3,608
Changes in current assets and liabilities, net of acquisitions:
Receivables	(43,478		)	(44,909		)
Inventories	(13,573		)	(23,189		)
Other current assets	(15,799		)	(20,555		)
Accounts payable	11,611			7,339
Other current liabilities	(6,387		)	33,214
Other noncurrent changes	(4,460		)	(14,626		)
Net cash provided by continuing operations	105,647			128,178
Net cash provided by (used in) discontinued operations	33,846			(25,529		)
Net cash provided by operating activities	139,493			102,649
Investing activities:
Capital expenditures	(143,764		)	(220,098		)
Net proceeds from sale or disposition of property and other	119,361			14,778
Investments	(358		)	(262		)
Net cash used in continuing operations	(24,761		)	(205,582		)
Net cash provided by discontinued operations	2,234			28,040
Net cash used in investing activities	(22,527		)	(177,542		)
Financing activities:
Issuance of long-term debt	63,827			387,625
Repayment of long-term debt	(93,275		)	(196,771		)
Dividends paid	(75,535		)	(73,575		)
Redemption of preferred stock	(15,600		)	—
Repurchase of common stock	(1,684		)	—
Tax withholding on stock-based compensation	(757		)	(323		)
Net cash provided by (used in) continuing operations	(123,024		)	116,956
Net cash used in discontinued operations	—			(40,852		)
Net cash provided by (used in) financing activities	(123,024		)	76,104
Effect of exchange rate changes on cash and cash equivalents	(1		)	3
Increase (decrease) in cash and cash equivalents	(6,059		)	1,214
Cash and cash equivalents -- beginning of year	46,107			83,903
Cash and cash equivalents -- end of period	$	40,048		$	85,117

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

MDU Resources Group, Inc.

Notes to Consolidated

Financial Statements

June 30, 2017 and 2016

(Unaudited)

Note 1 - Basis of presentation

The accompanying consolidated interim financial statements were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2016 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after June 30, 2017, up to the date of issuance of these consolidated interim financial statements.

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

Note 2 - Seasonality of operations

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

Note 3 - Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $32.7 million, $31.7 million and $29.2 million at June 30, 2017 and 2016, and December 31, 2016, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at June 30, 2017 and 2016, and December 31, 2016, was $9.2 million, $11.0 million and $10.5 million, respectively.

Note 4 - Inventories and natural gas in storage

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



	June 30, 2017		June 30, 2016		December 31, 2016
	(In thousands)
Aggregates held for resale	$	123,316	$	130,544	$	115,471
Asphalt oil	46,852		42,591		29,103
Materials and supplies	22,657		20,765		18,372
Merchandise for resale	16,164		18,439		16,437
Natural gas in storage (current)	14,126		19,689		25,761
Other	26,755		33,821		33,129
Total	$	249,870	$	265,849	$	238,273

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

Note 5 - Earnings (loss) per common share

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
	(In thousands)
Weighted average common shares outstanding - basic	195,304	195,304	195,304	195,294
Effect of dilutive performance share awards	669	395	689	384
Weighted average common shares outstanding - diluted	195,973	195,699	195,993	195,678
Shares excluded from the calculation of diluted earnings per share	—	—	—	—

Note 6 - New accounting standards

Recently adopted accounting standards

Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. The guidance requires all deferred tax assets and liabilities to be classified as noncurrent. These amendments align GAAP with IFRS. The Company adopted the guidance in the fourth quarter of 2016 and applied the retrospective method of adoption. The guidance required a reclassification of current deferred income taxes to noncurrent deferred income taxes on the Consolidated Balance Sheets, but did not impact the Company's results of operations or cash flows. As a result of the retrospective application of this change in accounting principle, the Company reclassified deferred income taxes of $33.9 million from current assets - deferred income taxes to deferred credits and other liabilities - deferred income taxes on its Consolidated Balance Sheet at June 30, 2016.

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

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

Recently issued accounting standards not yet adopted

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

The Company plans to adopt the guidance on January 1, 2018, and to use the modified retrospective approach. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. In addition, the guidance will require expanded disclosures, both quantitative and qualitative, related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The Company does not anticipate a significant change in the timing of revenue recognition and

continues to evaluate all revenue streams to determine what effect the guidance will have on its results of operations, financial position, cash flows and disclosures.

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

Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued guidance to clarify the classification of certain cash receipts and payments in the statement of cash flows. The guidance is intended to standardize the presentation and classification of certain transactions, including cash payments for debt prepayment or extinguishment, proceeds from insurance claim settlements and distributions from equity method investments. In addition, the guidance clarifies how to classify transactions that have characteristics of more than one class of cash flows. This guidance will be effective for the Company on January 1, 2018, with early adoption permitted. An entity that elects early adoption must adopt all the amendments in the same period and apply any adjustments as of the beginning of the fiscal year. Entities must apply the guidance retrospectively unless it is impracticable to do so, in which case they may apply it prospectively as of the earliest date practicable. The Company is evaluating the effects the adoption of the new guidance will have on its cash flows and disclosures.

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

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

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

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

Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.

Note 7 - Comprehensive income (loss)

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



Three Months Ended June 30, 2017	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,209	)	$	(33,781	)	$	(140	)	$	(55	)	$	(36,185	)
Other comprehensive loss before reclassifications	—			—			(15		)	(24		)	(39		)
Amounts reclassified from accumulated other comprehensive loss	92			312			—			31			435
Net current-period other comprehensive income (loss)	92			312			(15		)	7			396
Balance at end of period	$	(2,117	)	$	(33,469	)	$	(155	)	$	(48	)	$	(35,789	)



Three Months Ended June 30, 2016	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,575	)	$	(35,852	)	$	(175	)	$	20		$	(38,582	)
Other comprehensive income (loss) before reclassifications	—			—			31			(30		)	1
Amounts reclassified from accumulated other comprehensive loss	91			248			—			36			375
Net current-period other comprehensive income	91			248			31			6			376
Balance at end of period	$	(2,484	)	$	(35,604	)	$	(144	)	$	26		$	(38,206	)



Six Months Ended June 30, 2017	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,300	)	$	(33,221	)	$	(149	)	$	(63	)	$	(35,733	)
Other comprehensive loss before reclassifications	—			—			(6		)	(51		)	(57		)
Amounts reclassified from accumulated other comprehensive loss	183			669			—			66			918
Amounts reclassified to accumulated other comprehensive loss from a regulatory asset	—			(917		)	—			—			(917		)
Net current-period other comprehensive income (loss)	183			(248		)	(6		)	15			(56		)
Balance at end of period	$	(2,117	)	$	(33,469	)	$	(155	)	$	(48	)	$	(35,789	)



Six Months Ended June 30, 2016	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)
Balance at beginning of period	$	(2,667	)	$	(34,257	)	$	(200	)	$	(24	)	$	(37,148	)
Other comprehensive income (loss) before reclassifications	—			—			56			(19		)	37
Amounts reclassified from accumulated other comprehensive loss	183			(1,347		)	—			69			(1,095		)
Net current-period other comprehensive income (loss)	183			(1,347		)	56			50			(1,058		)
Balance at end of period	$	(2,484	)	$	(35,604	)	$	(144	)	$	26		$	(38,206	)

Reclassifications out of accumulated other comprehensive loss were as follows:



	Three Months Ended						Six Months Ended						Location on Consolidated Statements of Income
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income (loss)	$	(148	)	$	(147	)	$	(295	)	$	(297	)	Interest expense
	56			56			112			114			Income taxes
	(92		)	(91		)	(183		)	(183		)
Amortization of postretirement liability gains (losses) included in net periodic benefit cost (credit)	(502		)	(398		)	(1,075		)	2,166			(a)
	190			150			406			(819		)	Income taxes
	(312		)	(248		)	(669		)	1,347
Reclassification adjustment for loss on available-for-sale investments included in net income (loss)	(48		)	(55		)	(102		)	(106		)	Other income
	17			19			36			37			Income taxes
	(31		)	(36		)	(66		)	(69		)
Total reclassifications	$	(435	)	$	(375	)	$	(918	)	$	1,095

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

Note 8 - Assets held for sale and discontinued operations

Assets held for sale

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

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

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



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

Discontinued operations

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

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

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

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



	June 30, 2017			June 30, 2016		December 31, 2016
	(In thousands)
Assets
Current assets:
Receivables, net	$	—		$	433	$	—
Income taxes receivable	5,552		(a)	12,550		13,987
Prepayments and other current assets	—			11,083		—
Total current assets held for sale	5,552			24,066		13,987
Noncurrent assets:
Deferred income taxes	—			57,644		—
Total noncurrent assets held for sale	—			57,644		—
Total assets held for sale	$	5,552		$	81,710	$	13,987
Liabilities
Current liabilities:
Accounts payable	$	—		$	7,170	$	7,425
Other accrued liabilities	—			8,303		—
Total current liabilities held for sale	—			15,473		7,425
Noncurrent liabilities:
Deferred income taxes (b)	55			—		14
Total noncurrent liabilities held for sale	55			—		14
Total liabilities held for sale	$	55		$	15,473	$	7,439


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


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

reflected in noncurrent assets held for sale.

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

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

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 all of Fidelity's oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. The sale of Fidelity was part of the Company's strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value.

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



	June 30, 2017		June 30, 2016		December 31, 2016
	(In thousands)
Assets
Current assets:
Receivables, net	$	328	$	8,207	$	355
Income taxes receivable	—		5,348		—
Prepayments and other current assets	—		4		—
Total current assets held for sale	328		13,559		355
Noncurrent assets:
Net property, plant and equipment	2,064		5,507		5,507
Deferred income taxes	74,013		104,726		91,098
Other	161		161		161
Less allowance for impairment of assets held for sale	—		938		938
Total noncurrent assets held for sale	76,238		109,456		95,828
Total assets held for sale	$	76,566	$	123,015	$	96,183
Liabilities
Current liabilities:
Accounts payable	$	138	$	456	$	141
Taxes payable	7,171		—		19		(a)
Accrued compensation	—		1,459		—
Other accrued liabilities	2,724		10,849		2,358
Total current liabilities held for sale	10,033		12,764		2,518
Total liabilities held for sale	$	10,033	$	12,764	$	2,518


(a)	On the Company's Consolidated Balance Sheets, this amount was reclassified to prepayments and other current assets and is reflected

in current assets held for sale.

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

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

The Company incurred transaction costs of approximately $300,000 in the first quarter of 2016. In addition to the transaction costs, and due in part to the change in plans to sell the assets of Fidelity rather than sell Fidelity as a company, Fidelity incurred and expensed approximately $3.8 million and $5.6 million of exit and disposal costs for the three and six months ended

June 30, 2016, respectively, and has incurred $10.5 million of exit and disposal costs to date. Fidelity incurred no exit and disposal costs for the three and six months ended June 30, 2017, and the Company does not expect to incur any additional material exit and disposal costs. The exit and disposal costs are associated with severance and other related matters and exclude the office lease expiration discussed in the following paragraph.

Fidelity vacated its office space in Denver, Colorado in 2016. The Company incurred lease payments of approximately $400,000 and $900,000 for the three and six months ended June 30, 2016, respectively. A lease termination payment of $3.2 million was made during the second quarter of 2016. Existing office furniture and fixtures were relinquished to the lessor in the second quarter of 2016.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands)
Operating revenues	$	130		$	74,756		$	235		$	122,732
Operating expenses	1,205			443,756			(5,372		)	513,526
Operating income (loss)	(1,075		)	(369,000		)	5,607			(390,794		)
Other income (expense)	3			183			(13		)	387
Interest expense	239			832			239			1,753
Income (loss) from discontinued operations before income taxes	(1,311		)	(369,649		)	5,355			(392,160		)
Income taxes	1,879			(93,547		)	6,859			(98,022		)
Loss from discontinued operations	(3,190		)	(276,102		)	(1,504		)	(294,138		)
Loss from discontinued operations attributable to noncontrolling interest	—			(120,651		)	—			(131,691		)
Loss from discontinued operations attributable to the Company	$	(3,190	)	$	(155,451	)	$	(1,504	)	$	(162,447	)

The pretax income (loss) from discontinued operations attributable to the Company, related to the operations of and activity associated with Dakota Prairie Refining, were $0 and $(244.0) million for the three months ended and $6.9 million and $(253.9) million for the six months ended June 30, 2017 and 2016, respectively.

Note 9 - Goodwill and other intangible assets

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



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



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

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



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

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

Other amortizable intangible assets were as follows:



	June 30, 2017		June 30, 2016		December 31, 2016
	(In thousands)
Customer relationships	$	15,745	$	17,145	$	17,145
Less accumulated amortization	13,302		13,108		13,917
	2,443		4,037		3,228
Noncompete agreements	2,430		2,430		2,430
Less accumulated amortization	1,732		1,585		1,658
	698		845		772
Other	7,086		7,764		7,768
Less accumulated amortization	5,442		5,486		5,843
	1,644		2,278		1,925
Total	$	4,785	$	7,160	$	5,925

Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2017, was $600,000 and $1.2 million, respectively. Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2016, was $600,000 and $1.3 million, respectively. Estimated amortization expense for amortizable intangible assets is $2.2 million in 2017, $1.2 million in 2018, $1.0 million in 2019, $500,000 in 2020, $200,000 in 2021 and $800,000 thereafter.

Note 10 - Fair value measurements

The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $73.1 million, $71.4 million and $70.9 million, at June 30, 2017 and 2016, and December 31, 2016, respectively, are classified as investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were $2.1 million and $5.0 million for the three and six months ended June 30, 2017. The net unrealized gains on these investments were $2.3 million and $3.9 million for the three and six months ended June 30, 2016. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

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



June 30, 2017	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	9,743	$	13	$	(86	)	$	9,670
U.S. Treasury securities	613		—		—			613
Total	$	10,356	$	13	$	(86	)	$	10,283



June 30, 2016	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	10,420	$	52	$	(12	)	$	10,460
Total	$	10,420	$	52	$	(12	)	$	10,460



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

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

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

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

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

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

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

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



	Fair Value Measurements at June 30, 2017, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at June 30, 2017
	(In thousands)
Assets:
Money market funds	$	—	$	5,882	$	—	$	5,882
Insurance contract*	—		73,126		—		73,126
Available-for-sale securities:
Mortgage-backed securities	—		9,670		—		9,670
U.S. Treasury securities	—		613		—		613
Total assets measured at fair value	$	—	$	89,291	$	—	$	89,291


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



	Fair Value Measurements at June 30, 2016, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at June 30, 2016
	(In thousands)
Assets:
Money market funds	$	—	$	1,525	$	—	$	1,525
Insurance contract*	—		71,355		—		71,355
Available-for-sale securities:
Mortgage-backed securities	—		10,460		—		10,460
Total assets measured at fair value	$	—	$	83,340	$	—	$	83,340


*	The insurance contract invests approximately 66 percent in fixed-income investments, 17 percent in common stock of large-cap companies, 9 percent in common stock of mid-cap companies, 6 percent in common stock of small-cap companies, 1 percent in target date investments and 1 percent in cash equivalents.



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


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

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

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



	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at June 30, 2017	$	1,761,476	$	1,864,884
Long-term debt at June 30, 2016	$	1,987,307	$	2,134,708
Long-term debt at December 31, 2016	$	1,790,159	$	1,841,885

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

Note 11 - Equity

A summary of the changes in equity was as follows:



Six Months Ended June 30, 2017	Total Equity
	(In thousands)
Balance at December 31, 2016	$	2,316,244
Net income	78,539
Other comprehensive loss	(56		)
Dividends declared on preferred stocks	(171		)
Dividends declared on common stock	(75,192		)
Stock-based compensation	1,629
Repurchase of common stock	(1,684		)
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	(757		)
Redemption of preferred stock	(15,600		)
Balance at June 30, 2017	$	2,302,952

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



Six Months Ended June 30, 2016	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2015	$	2,396,505		$	124,043		$	2,520,548
Net loss	(84,283		)	(131,691		)	(215,974		)
Other comprehensive loss	(1,058		)	—			(1,058		)
Dividends declared on preferred stocks	(343		)	—			(343		)
Dividends declared on common stock	(73,239		)	—			(73,239		)
Stock-based compensation	2,015			—			2,015
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	(323		)	—			(323		)
Net tax deficit on stock-based compensation	(1,664		)	—			(1,664		)
Contribution from noncontrolling interest	—			7,648			7,648
Balance at June 30, 2016	$	2,237,610		$	—		$	2,237,610

Note 12 - Cash flow information

Cash expenditures for interest and income taxes were as follows:



	Six Months Ended
	June 30,
	2017		2016
	(In thousands)
Interest, net of amount capitalized and AFUDC - borrowed of $418 and $548 in 2017 and 2016, respectively	$	39,207	$	44,860
Income taxes paid, net*	$	32,388	$	29,891


*	Income taxes refunded, net of discontinued operations, were $(3.6) million and $(500,000) for the six months ended June 30, 2017 and 2016, respectively.

Noncash investing transactions were as follows:

Note 13 - Business segment data

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

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

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

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

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

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

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

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands)
External operating revenues:
Regulated operations:
Electric	$	74,574		$	73,832		$	162,799		$	156,755
Natural gas distribution	131,592			112,770			474,111			412,165
Pipeline and midstream	19,319			19,450			22,190			22,998
	225,485			206,052			659,100			591,918
Nonregulated operations:
Pipeline and midstream	4,520			10,268			8,163			18,966
Construction materials and contracting	501,426			541,257			702,203			751,108
Construction services	336,009			285,924			635,580			541,424
Other	199			447			519			747
	842,154			837,896			1,346,465			1,312,245
Total external operating revenues	$	1,067,639		$	1,043,948		$	2,005,565		$	1,904,163

Intersegment operating revenues:
Regulated operations:
Electric	$	—		$	—		$	—		$	—
Natural gas distribution	—			—			—			—
Pipeline and midstream	6,353			6,594			27,841			27,691
	6,353			6,594			27,841			27,691
Nonregulated operations:
Pipeline and midstream	59			36			93			119
Construction materials and contracting	172			97			258			215
Construction services	295			77			301			539
Other	1,758			1,669			3,501			3,338
	2,284			1,879			4,153			4,211
Intersegment eliminations	(8,637		)	(8,473		)	(31,994		)	(31,902		)
Total intersegment operating revenues	$	—		$	—		$	—		$	—



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In thousands)
Earnings (loss) on common stock:
Regulated operations:
Electric	$	7,859		$	8,022		$	22,191		$	19,141
Natural gas distribution	(2,797		)	(7,777		)	25,064			17,464
Pipeline and midstream	5,492			5,564			10,048			10,852
	10,554			5,809			57,303			47,457
Nonregulated operations:
Pipeline and midstream	(238		)	737			(865		)	739
Construction materials and contracting	21,168			33,696			1,255			19,225
Construction services	12,391			6,990			19,753			12,964
Other	(2,163		)	(1,105		)	(2,440		)	(2,564		)
	31,158			40,318			17,703			30,364
Intersegment eliminations*	2,093			—			4,266			—
Earnings on common stock before loss from discontinued operations	43,805			46,127			79,272			77,821
Loss from discontinued operations, net of tax*	(3,190		)	(276,102		)	(1,504		)	(294,138		)
Loss from discontinued operations attributable to noncontrolling interest	—			(120,651		)	—			(131,691		)
Total earnings (loss) on common stock	$	40,615		$	(109,324	)	$	77,768		$	(84,626	)

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

Note 14 - Employee benefit plans

Pension and other postretirement plans

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



	Pension Benefits						Other Postretirement Benefits
Three Months Ended June 30,	2017			2016			2017			2016
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	306		$	374
Interest cost	4,089			4,220			825			895
Expected return on assets	(5,234		)	(5,182		)	(1,175		)	(1,118		)
Amortization of prior service credit	—			—			(343		)	(343		)
Amortization of net actuarial loss	1,385			1,514			100			299
Net periodic benefit cost (credit), including amount capitalized	240			552			(287		)	107
Less amount capitalized	73			121			(114		)	4
Net periodic benefit cost (credit)	$	167		$	431		$	(173	)	$	103



	Pension Benefits						Other Postretirement Benefits
Six Months Ended June 30,	2017			2016			2017			2016
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	—		$	—		$	753		$	824
Interest cost	8,103			8,610			1,633			1,844
Expected return on assets	(10,263		)	(10,462		)	(2,320		)	(2,267		)
Amortization of prior service credit	—			—			(686		)	(686		)
Amortization of net actuarial loss	3,178			3,107			436			747
Net periodic benefit cost (credit), including amount capitalized	1,018			1,255			(184		)	462
Less amount capitalized	180			202			(153		)	38
Net periodic benefit cost (credit)	$	838		$	1,053		$	(31	)	$	424

Nonqualified benefit plans

In addition to the qualified plan defined pension benefits reflected in the table, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or, upon death, to their beneficiaries for a 15-year period. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated benefit increases. Vesting for participants not fully vested was retained. The Company's net periodic benefit cost for these plans for the three and six months ended June 30, 2017, was $1.1 million and $2.3 million, respectively. The Company's net periodic benefit cost for these plans for the three months ended June 30, 2016, was $1.2 million. The Company's net periodic benefit credit for these plans for the six months ended June 30, 2016, was $700,000, which reflects a curtailment gain of $3.3 million in the first quarter of 2016.

Note 15 - Regulatory matters

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

On August 12, 2016, Intermountain filed an application with the IPUC for a natural gas rate increase of approximately $10.2 million annually or approximately 4.1 percent above current rates. The request includes rate recovery associated with increased investment in facilities and increased operating expenses. On January 17, 2017, Intermountain provided the IPUC with an updated revenue request of approximately $9.4 million. On April 28, 2017, the IPUC issued an order approving an increase of approximately $4.1 million or approximately 1.6 percent above current rates based on a 9.5 percent return on equity effective with service rendered on and after May 1, 2017. On May 18, 2017, Intermountain filed a petition for reconsideration with the IPUC requesting the reconsideration of certain items denied in the April 28 order. On June 15, 2017, the IPUC granted the request for reconsideration. The IPUC has 13 weeks to complete the reconsideration and until the middle of September 2017 to issue a final order of reconsideration.

On December 2, 2016, Montana-Dakota filed an application with the MTPSC requesting authority to implement gas and electric tax tracking adjustments for Montana state and local taxes and fees that reflect the changes in state and local property taxes applicable to natural gas and electric utilities pursuant to Montana law. The requested tax tracking adjustments would result in an increase in revenues of approximately $814,000. On January 17, 2017, the MTPSC issued an order on the tax tracking adjustments. The gas tracking adjustment was approved as an increase to revenues of approximately $474,000 effective January 1, 2017. The electric tax tracking adjustment was approved as an increase to revenues of approximately $251,000 effective May 15, 2017. Montana-Dakota filed a motion for reconsideration of the electric tax tracking adjustment on January 27, 2017. On May 30, 2017, the MTPSC granted Montana-Dakota's motion for reconsideration allowing the full amount of electric taxes covered in the stipulated tariffs to be recovered. The additional revenues of approximately $88,000 will be included in a true-up to be effective in 2018.

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

On April 1, 2017, Montana-Dakota implemented Phase 2 of the electric rate case approved by the MTPSC on March 25, 2016. The annual increase of $4.7 million is effective with service rendered on and after April 1, 2017.

On May 31, 2017, Cascade filed an application with the WUTC for an annual pipeline replacement cost recovery mechanism of approximately $1.6 million or approximately .75 percent of additional revenue. The requested increase includes incremental pipeline replacement investments associated with qualifying pipeline integrity projects. If approved, rates will be effective November 1, 2017. This matter is pending before the WUTC.

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

On July 21, 2017, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase of approximately $5.9 million annually or approximately 5.4 percent above current rates. The requested increase is primarily to recover the increased investment in distribution facilities to enhance system safety and reliability and the depreciation and taxes associated with the increase in investment. Montana-Dakota is also introducing a System Safety Integrity Program and the proposed adjustment mechanism required to fund the System Safety Integrity Program. Montana-Dakota has requested an interim increase of approximately $4.6 million or approximately 4.2 percent, subject to refund. This matter is pending before the NDPSC.

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

Montana-Dakota previously filed an application with the NDPSC on October 14, 2016, for an electric rate increase which also included a requested return on equity to be used in the determination of applications previously filed by Montana-Dakota for a renewable resource cost adjustment rider, an electric generation resource recovery rider, and a transmission cost adjustment rider, as discussed in the following paragraphs. On April 7, 2017, Montana-Dakota, the NDPSC Advocacy Staff and the interveners in the case filed a settlement agreement resolving all issues in the general rate case. The settlement agreement included a net increase of approximately $7.5 million or 3.7 percent above previously approved final rates and a true-up of the return on equity used in the interim renewable resource cost adjustment, the electric generation resource recovery and transmission cost adjustment riders of 9.45 percent; a return on equity of 9.65 percent for base rates and the renewable resource cost adjustment rider on a go-forward basis; and a return on equity of 9.45 percent through December 31, 2019, for the natural gas-fired internal combustion engines and associated facilities included in the electric generation resource recovery rider. A hearing on the settlement agreement was held on April 10, 2017. On June 16, 2017, the NDPSC approved the settlement agreement. On June 26, 2017, Montana-Dakota submitted a compliance filing and on July 14, 2017, submitted updated tariff sheets and a refund plan. The NDPSC approved the compliance filing and refund plan on July 26, 2017, with final rates effective with service rendered on or after August 7, 2017. The final rates are less than the interim rates currently in effect. Therefore, Montana-Dakota will refund the difference to customers, which is approximately 19 percent of the amount collected from the general rate case interim increase, along with refunds to reflect true-ups for the various riders, as applicable. The background information related to the settlement agreement and related applications are discussed in the following paragraphs.

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

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

On November 25, 2015, Montana-Dakota filed an application with the NDPSC for an update of its transmission cost adjustment rider for recovery of MISO-related charges and two transmission projects in North Dakota. On February 10, 2016, the NDPSC approved the transmission cost adjustment effective with service rendered on and after February 12, 2016, resulting in an annual increase on an interim basis, subject to refund, of $6.8 million based upon a 10.5 percent return on equity to be finalized upon approval of the electric rate case filed on October 14, 2016. The electric rate case settlement agreement filed on April 7, 2017,

included a revised return on equity for the rider. The settlement agreement was approved on June 16, 2017, as previously discussed in this note.

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

Note 16 - Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries, which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. Accruals are based on the best information available, but in certain situations management is unable to estimate an amount or range of a reasonably possible loss including, but not limited to when: (1) the damages are unsubstantiated or indeterminate, (2) the proceedings are in the early stages, (3) numerous parties are involved, or (4) the matter involves novel or unsettled legal theories. The Company had accrued liabilities of $33.7 million, $27.4 million and $31.8 million, which have not been discounted, including liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at June 30, 2017 and 2016, and December 31, 2016, respectively, including amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note. The Company will continue to monitor each matter and adjust accruals as might be warranted based on new information and further developments. Management believes that the outcomes with respect to probable and reasonably possible losses in excess of the amounts accrued, net of insurance recoveries, while uncertain, either can’t be estimated or will not have a material effect upon the Company's financial position, results of operations or cash flows. Unless otherwise required by GAAP, legal costs are expensed as they are incurred.

Litigation

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

Environmental matters

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

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

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

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

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

The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. The EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. In April 2010, the Washington DOE issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Current estimates for the cost to complete the remedial investigation and feasibility study are approximately $7.6 million of which $200,000 has been incurred. Cascade has accrued $7.4 million for the remedial investigation and feasibility study as well as $6.4 million for remediation of this site; however, the accrual for remediation costs will be reviewed and adjusted, if necessary, after completion of the remedial investigation and feasibility study. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

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

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

Guarantees

In June 2016, WBI Energy sold all of the outstanding membership interests in Dakota Prairie Refining. In connection with the sale, Centennial agreed to continue to guarantee certain debt obligations of Dakota Prairie Refining which totaled $58.5 million at June 30, 2017, and are expected to mature by 2023. Tesoro agreed to indemnify Centennial for any losses and litigation expenses arising from the guarantee. The estimated fair values of the indemnity asset and guarantee liability are reflected in deferred charges and other assets - other and deferred credits and other liabilities - other, respectively, on the Consolidated Balance Sheets. Continuation of the guarantee was required as a condition to the sale of Dakota Prairie Refining.

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

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

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, insurance deductibles and loss limits, and certain other guarantees. At June 30, 2017, the fixed maximum amounts guaranteed under these agreements aggregated $106.2 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $6.6 million in 2017; $24.8 million in 2018; $20.2 million in 2019; $47.4 million in 2020; $500,000 in 2021; $2.7 million thereafter; and $4.0 million, which has no scheduled maturity date. There were no amounts outstanding under the above guarantees at June 30, 2017. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At June 30, 2017, the fixed maximum amounts guaranteed under these letters of credit aggregated $33.8 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate $33.1 million in 2017 and $700,000 in 2018. There were no amounts outstanding under the above letters of credit at June 30, 2017. In the event of default under these letter of credit obligations, the subsidiary issuing the letter of credit for that particular obligation would be required to make payments under its letter of credit.

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

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At June 30, 2017, approximately $765.5 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 May 2016 through December 2040. Coal purchased under the coal supply agreement is reflected in inventories on the Company's Consolidated Balance Sheets and is recovered from customers as a component of electric fuel and purchased power.

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

At June 30, 2017, the Company's exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, was $42.1 million.

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

Overview

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 as well as a continued disciplined approach to the acquisition of well-managed companies and properties


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


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


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

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

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

Key Strategies and Challenges

Electric and Natural Gas Distribution

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

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

Pipeline and Midstream

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

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

Construction Materials and Contracting

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

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

Construction Services

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

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

Additional Information

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

Earnings Overview

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In millions, except per share amounts)
Electric	$	7.8		$	8.0		$	22.2		$	19.2
Natural gas distribution	(2.8		)	(7.8		)	25.1			17.5
Pipeline and midstream	5.3			6.3			9.2			11.6
Construction materials and contracting	21.2			33.7			1.3			19.2
Construction services	12.4			7.0			19.7			13.0
Other	(2.2		)	(1.1		)	(2.5		)	(2.6		)
Intersegment eliminations	2.1			—			4.3			—
Earnings before discontinued operations	43.8			46.1			79.3			77.9
Loss from discontinued operations, net of tax	(3.2		)	(276.1		)	(1.5		)	(294.2		)
Loss from discontinued operations attributable to noncontrolling interest	—			(120.7		)	—			(131.7		)
Earnings (loss) on common stock	$	40.6		$	(109.3	)	$	77.8		$	(84.6	)
Earnings (loss) per common share – basic:
Earnings before discontinued operations	$	.22		$	.24		$	.41		$	.40
Discontinued operations attributable to the Company, net of tax	(.01		)	(.80		)	(.01		)	(.83		)
Earnings (loss) per common share – basic	$	.21		$	(.56	)	$	.40		$	(.43	)
Earnings (loss) per common share – diluted:
Earnings before discontinued operations	$	.22		$	.24		$	.40		$	.40
Discontinued operations attributable to the Company, net of tax	(.01		)	(.80		)	—			(.83		)
Earnings (loss) per common share – diluted	$	.21		$	(.56	)	$	.40		$	(.43	)

Three Months Ended June 30, 2017 and 2016 The Company recognized consolidated earnings of $40.6 million for the quarter ended June 30, 2017, compared to a consolidated loss of $109.3 million from the comparable prior period largely due to:


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


•	Higher inside workloads and margins at the construction services business


•	Higher natural gas retail sales volumes at the natural gas distribution business

These increases were partially offset by lower asphalt product volumes and margins and lower construction margins at the construction materials and contracting business.

Six Months Ended June 30, 2017 and 2016 The Company recognized consolidated earnings of $77.8 million for the six months ended June 30, 2017, compared to a consolidated loss of $84.6 million from the comparable prior period largely due to:


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


•	Higher inside workloads and margins at the construction services business


•	Higher natural gas retail sales volumes at the natural gas distribution business

These increases were partially offset by:


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


•	Lower earnings due to the sale of Pronghorn in January 2017 at the pipeline and midstream business

Financial and Operating Data

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

Electric



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(Dollars in millions, where applicable)
Operating revenues	$	74.6	$	73.8	$	162.8	$	156.8
Operating expenses:
Electric fuel and purchased power	16.8		15.9		38.6		37.9
Operation and maintenance	28.9		28.8		57.0		55.8
Depreciation, depletion and amortization	11.4		12.4		23.4		25.3
Taxes, other than income	3.9		3.3		7.4		6.6
	61.0		60.4		126.4		125.6
Operating income	13.6		13.4		36.4		31.2
Earnings	$	7.8	$	8.0	$	22.2	$	19.2
Retail sales (million kWh):
Residential	225.7		235.5		581.5		559.1
Commercial	348.0		342.6		744.9		716.3
Industrial	120.4		132.2		262.3		275.9
Other	24.8		21.8		47.2		43.2
	718.9		732.1		1,635.9		1,594.5
Average cost of electric fuel and purchased power per kWh	$	.021	$	.020	$	.022	$	.022

Three Months Ended June 30, 2017 and 2016 Electric earnings decreased $200,000 (2 percent) compared to the comparable prior period largely due to:


•	Higher taxes, other than income of $400,000 (after tax) due to higher property taxes in certain jurisdictions


•	Lower retail sales margins due to lower retail sales volumes of 2 percent, primarily to industrial and residential customers, largely offset by the recovery of additional investment in a MISO project and approved final and interim rate increases offset in part by a true-up of interim rates to reflect the approved settlement of the North Dakota electric case in June 2017

Partially offsetting these decreases was lower depreciation, depletion and amortization expense due to lower depreciation rates implemented in conjunction with regulatory recovery activity.

Six Months Ended June 30, 2017 and 2016 Electric earnings increased $3.0 million (16 percent) compared to the comparable prior period due to:


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


•	Lower depreciation, depletion and amortization expense of $1.2 million (after tax) due to lower depreciation rates implemented in conjunction with regulatory recovery activity

Partially offsetting these increases were:


•	Higher operation and maintenance expense, which includes $700,000 (after tax) due to higher payroll-related costs and timing of software maintenance costs


•	Higher taxes, other than income, which includes $400,000 (after tax) due to higher property taxes in certain jurisdictions

Natural Gas Distribution



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(Dollars in millions, where applicable)
Operating revenues	$	131.6		$	112.8		$	474.1		$	412.2
Operating expenses:
Purchased natural gas sold	64.1			54.0			278.5			236.1
Operation and maintenance	38.8			38.3			79.7			77.1
Depreciation, depletion and amortization	17.2			16.6			34.2			32.9
Taxes, other than income	10.4			9.6			29.1			26.4
	130.5			118.5			421.5			372.5
Operating income (loss)	1.1			(5.7		)	52.6			39.7
Earnings (loss)	$	(2.8	)	$	(7.8	)	$	25.1		$	17.5
Volumes (MMdk)
Sales:
Residential	8.3			6.9			36.5			30.3
Commercial	6.0			5.1			25.1			20.7
Industrial	1.0			.9			2.5			2.2
	15.3			12.9			64.1			53.2
Transportation:
Commercial	.4			.4			1.1			.9
Industrial	28.2			30.1			66.2			70.9
	28.6			30.5			67.3			71.8
Total throughput	43.9			43.4			131.4			125.0
Degree days (% of normal)*
Montana-Dakota/Great Plains	96		%	96		%	97		%	83		%
Cascade	91		%	56		%	111		%	80		%
Intermountain	116		%	81		%	111		%	92		%
Average cost of natural gas, including transportation, per dk	$	4.17		$	4.18		$	4.35		$	4.44

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

Three Months Ended June 30, 2017 and 2016 Natural gas distribution experienced a seasonal loss of $2.8 million compared to a seasonal loss of $7.8 million a year ago (64 percent improvement). The improvement was the result of:


•	Higher natural gas retail sales margins resulting from higher retail sales volumes of 19 percent to all customer classes, primarily colder weather in all regions and customer growth, as well as approved rate recovery; offset in part by decoupling and weather normalization in certain jurisdictions


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

Partially offsetting these increases was higher depreciation, depletion and amortization expense of $400,000 (after tax) due to increased property, plant and equipment balances.

Six Months Ended June 30, 2017 and 2016 Natural gas distribution earnings increased $7.6 million (44 percent) compared to the comparable prior period due to:


•	Higher natural gas retail sales margins resulting from higher retail sales volumes of 21 percent to all customer classes, primarily colder weather in all regions and customer growth, as well as approved rate recovery; offset in part by decoupling and weather normalization in certain jurisdictions


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

Partially offsetting these increases were:


•	Higher operation and maintenance expense of $1.5 million (after tax) primarily due to higher payroll-related costs and timing of software maintenance costs


•	Higher depreciation, depletion and amortization expense of $800,000 (after tax) due to increased property, plant and equipment balances

Pipeline and Midstream



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017			2016
	(Dollars in millions)
Operating revenues	$	30.2	$	36.3	$	58.3		$	69.7
Operating expenses:
Operation and maintenance	13.7		15.1		27.2			29.0
Depreciation, depletion and amortization	4.1		6.1		8.2			12.4
Taxes, other than income	3.1		3.1		6.1			5.8
	20.9		24.3		41.5			47.2
Operating income	9.3		12.0		16.8			22.5
Earnings	$	5.3	$	6.3	$	9.2		$	11.6
Transportation volumes (MMdk)	79.4		74.1		146.5			149.4
Natural gas gathering volumes (MMdk)	4.1		5.0		8.0			9.9
Customer natural gas storage balance (MMdk):
Beginning of period	15.0		14.5		26.4			16.6
Net injection (withdrawal)	10.1		13.6		(1.3		)	11.5
End of period	25.1		28.1		25.1			28.1

Three Months Ended June 30, 2017 and 2016 Pipeline and midstream earnings decreased $1.0 million (17 percent) compared to the comparable prior period, primarily the result of lower gathering and processing revenues of $3.5 million (after tax), largely due to lower volumes resulting from the sale of Pronghorn in January 2017.

Partially offsetting the decrease were:


•	Lower depreciation, depletion and amortization expense of $1.3 million (after tax), primarily the absence of Pronghorn


•	Lower operation and maintenance expense primarily due to the absence of Pronghorn


•	Lower interest expense of $500,000 (after tax) due to lower debt balances

Six Months Ended June 30, 2017 and 2016 Pipeline and midstream earnings decreased $2.4 million (21 percent) compared to the comparable prior period, primarily the result of lower gathering and processing revenues of $6.7 million (after tax), largely due to lower volumes resulting from the sale of Pronghorn, as well as lower gathering rates in certain operating areas.

Partially offsetting the decrease were:


•	Lower depreciation, depletion and amortization expense of $2.6 million (after tax), primarily the absence of Pronghorn


•	Lower operation and maintenance expense primarily due to the absence of Pronghorn


•	Lower interest expense of $1.0 million (after tax) due to lower debt balances

Construction Materials and Contracting



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(Dollars in millions)
Operating revenues	$	501.6	$	541.4	$	702.5	$	751.3
Operating expenses:
Operation and maintenance	437.2		456.6		643.1		661.2
Depreciation, depletion and amortization	14.4		14.8		28.1		29.9
Taxes, other than income	12.0		11.9		20.9		21.4
	463.6		483.3		692.1		712.5
Operating income	38.0		58.1		10.4		38.8
Earnings	$	21.2	$	33.7	$	1.3	$	19.2
Sales (000's):
Aggregates (tons)	7,374		7,659		10,879		11,285
Asphalt (tons)	1,830		2,213		2,045		2,452
Ready-mixed concrete (cubic yards)	1,037		1,050		1,599		1,694

Three Months Ended June 30, 2017 and 2016 Construction materials and contracting earnings decreased $12.5 million (37 percent) compared to the comparable prior period due to:


•	Lower asphalt product volumes and margins primarily due to weather-related delays, increased competition in certain regions and increasing material costs


•	Lower construction margins of $4.1 million (after tax) primarily due to lower revenues resulting from poor weather conditions that caused a delay in the start of projects


•	Lower aggregate margins of $1.0 million (after tax) primarily due to lower sales volumes, which reflects the effects of large projects in 2016 and weather-related delays; partially offset by strong commercial and residential demand in certain regions and lower production costs

Six Months Ended June 30, 2017 and 2016 Construction materials and contracting earnings decreased $17.9 million (93 percent) compared to the comparable prior period due to:


•	Lower asphalt product volumes and margins primarily due to the effects of large projects in 2016, weather-related delays and increased competition in certain regions


•	Lower construction margins of $7.4 million (after tax) primarily due to lower revenues resulting from poor weather conditions, as previously discussed, project timing and increased competition


•	Lower ready-mixed concrete margins of $2.2 million (after tax) due to lower volumes primarily resulting from poor weather conditions

Construction Services



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(In millions)
Operating revenues	$	336.3	$	286.0	$	635.9	$	542.0
Operating expenses:
Operation and maintenance	300.1		260.7		569.7		494.3
Depreciation, depletion and amortization	4.0		3.8		8.0		7.6
Taxes, other than income	11.5		9.7		24.8		20.4
	315.6		274.2		602.5		522.3
Operating income	20.7		11.8		33.4		19.7
Earnings	$	12.4	$	7.0	$	19.7	$	13.0

Three Months Ended June 30, 2017 and 2016 Construction services earnings increased $5.4 million (77 percent) compared to the comparable prior period due to:


•	Higher earnings of $5.5 million (after tax) resulting from higher inside workloads and margins largely due to an increase in the number and size of projects that moved into full construction during the quarter


•	Higher earnings resulting from higher outside margins due to successful execution of labor performance on projects

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

Six Months Ended June 30, 2017 and 2016 Construction services earnings increased $6.7 million (52 percent) compared to the comparable prior period due to:


•	Higher earnings of $11.1 million (after tax) resulting from higher inside workloads and margins in the majority of business activities


•	An increase in the number and size of projects that moved into full construction in 2017


•	Successful execution of labor performance on projects

Partially offsetting these increases were:


•	Higher selling, general and administrative expense of $2.1 million (after tax), primarily higher payroll-related costs


•	Absence in 2017 of a tax benefit of $1.5 million related to the disposition of a non-strategic asset


•	Lower outside earnings due to fewer significant customer projects in 2017

Other



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	(In millions)
Operating revenues	$	1.9		$	2.1		$	4.0		$	4.1
Operating expenses:
Operation and maintenance	4.4			2.2			5.6			3.9
Depreciation, depletion and amortization	.5			.5			1.1			1.0
Taxes, other than income	—			—			.1			.1
	4.9			2.7			6.8			5.0
Operating loss	(3.0		)	(.6		)	(2.8		)	(.9		)
Loss	$	(2.2	)	$	(1.1	)	$	(2.5	)	$	(2.6	)

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

Three Months Ended June 30, 2017 and 2016 Other loss increased $1.1 million compared to the comparable prior period primarily due to a loss on the disposition of certain assets offset in part by lower interest expense due to the repayment of long-term debt with the sale of the remaining exploration and production assets.

Six Months Ended June 30, 2017 and 2016 Other loss decreased $100,000 compared to the comparable prior period, primarily lower interest expense of $1.1 million (after tax) largely due to the repayment of long-term debt, as previously discussed, offset by higher operation and maintenance expense due to a loss on the disposition of certain assets and higher insurance costs offset in part by lower operation and maintenance expense at the refining business due to the sale of the business in June 2016.

Discontinued Operations



	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2017				2016			2017				2016
	(In millions)
Income (loss) from discontinued operations before intercompany eliminations, net of tax	$	(1.1	)		$	(285.1	)	$	2.8			$	(303.3	)
Intercompany eliminations	(2.1		)	*	9.0			(4.3		)	*	9.1
Loss from discontinued operations, net of tax	(3.2		)		(276.1		)	(1.5		)		(294.2		)
Loss from discontinued operations attributable to noncontrolling interest	—				(120.7		)	—				(131.7		)
Loss from discontinued operations attributable to the Company, net of tax	$	(3.2	)		$	(155.4	)	$	(1.5	)		$	(162.5	)

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

Three Months Ended June 30, 2017 and 2016 The Company's loss from discontinued operations was $3.2 million compared to a loss of $155.4 million for the comparable prior period. The decreased loss was largely due to the absence in 2017 of a loss associated with the sale of the refining business, which was sold in June 2016.

Six Months Ended June 30, 2017 and 2016 The Company's loss from discontinued operations was $1.5 million compared to a loss of $162.5 million for the comparable prior period. The decreased loss was largely due to the absence in 2017 of a loss associated with the sale of the refining business, as previously discussed.

Intersegment Transactions

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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017			2016		2017			2016
	(In millions)
Intersegment transactions:
Operating revenues	$	8.6		$	8.5	$	32.0		$	31.9
Purchased natural gas sold	6.4			6.6		27.9			27.6
Operation and maintenance	2.2			1.9		4.1			4.3
Income from continuing operations*	(2.1		)	—		(4.3		)	—

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

For more information on intersegment eliminations, see Note 13.

Prospective Information

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

MDU Resources Group, Inc.


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


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

Electric and natural gas distribution

•

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


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

•

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

•

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


•	In June 2017, the Company filed its 2017 North Dakota Electric Integrated Resource Plan. The plan includes the proposed purchase of the Thunder Spirit Wind farm expansion project and the development and design of a large combined-cycle natural gas-fired facility.


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


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


•	Regulatory actions

Completed Cases:

Since January 1, 2017, the Company has received approval on final rate increases totaling $33.0 million in annual revenue. This includes electric rate proceedings in Montana, North Dakota, South Dakota, Wyoming and before the FERC, and natural gas proceedings in Idaho, Minnesota, Montana and Oregon. Recently approved final rates include:


◦	On June 16, 2017, the NDPSC approved the settlement agreement filed by the Company on April 7, 2017, as discussed in Note 15.

Pending Cases:

The Company is requesting rate increases totaling $13.9 million in annual revenue. Cases recently filed include:


◦	On May 31, 2017, the Company filed an application with the WUTC for an annual pipeline replacement cost recovery mechanism, as discussed in Note 15.


◦	On June 30, 2017, the Company filed an application for advance determination of prudence and a certificate of public convenience and necessity with the NDPSC to purchase an expansion of the Thunder Spirit Wind farm, as discussed in Note 15.


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


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

Pipeline and midstream

•

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


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

•

In June 2017, the Company announced plans to complete a Line Section 27 expansion project. The project will include approximately 13 miles of new pipeline and associated facilities. The project, as designed, will increase capacity by over 200,000 dk per day and bring total capacity to over 600,000 dk per day. The project is expected to be placed in-service in the fall of 2018. The Company has signed long-term contracts supporting this expansion and expects construction costs to range from $27 million to $30 million.


•	The Company continues to focus on growing and improving existing operations through organic projects to become the leading pipeline company and midstream provider in all areas in which it operates.

Construction materials and contracting


•	Approximate work backlog at June 30, 2017, was $766 million, compared to $805 million a year ago.


•	Projected revenues are in the range of $1.8 billion to $1.9 billion for 2017.


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


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


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


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

Construction services


•	Approximate work backlog at June 30, 2017, was $596 million, compared to $508 million a year ago.


•	Projected revenues are in the range of $1.2 billion to $1.3 billion for 2017.


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


•	The Company continues to pursue opportunities for expansion in energy projects such as petrochemical, transmission, substations, utility services and renewables. Initiatives are aimed at capturing additional market share and expanding into new markets.


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


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

Liquidity and Capital Commitments

At June 30, 2017, the Company had cash and cash equivalents of $40.0 million and available borrowing capacity of $638.2 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 from various sources, including internally generated funds; the Company's credit facilities, as described in Capital resources; and through the issuance of long-term debt.

Cash flows

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

Cash flows provided by operating activities in the first six months of 2017 increased $36.8 million from the comparable period in 2016. The increase in cash flows provided by operating activities was largely related to the absence in 2017 of the use of cash at the exploration and production and refining businesses in 2016.

Investing activities Cash flows used in investing activities in the first six months of 2017 decreased $155.0 million from the comparable period in 2016. The decrease was primarily due to net proceeds from the sale of Pronghorn at the pipeline and midstream business along with lower capital expenditures primarily at the electric and construction services businesses. Partially offsetting the decrease was the absence of net proceeds from the sale of property at the exploration and production business.

Financing activities Cash flows used in financing activities in the first six months of 2017 was $123.0 million compared to cash flows provided by financing activities of $76.1 million in the first six months of 2016. The change was primarily due to lower issuance of long-term debt in 2017 of $323.8 million. Partially offsetting the change was lower repayment of long-term debt along with the absence in 2017 of the debt repayment in connection with the sale of the refining business in 2016.

Defined benefit pension plans

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

Capital expenditures

Capital expenditures for the first six months of 2017 were $132.1 million and are estimated to be approximately $515 million for 2017, which includes $150 million of additional growth capital that is not allocated to a specific business segment. Estimated capital expenditures include:


•	System upgrades


•	Routine replacements


•	Service extensions


•	Routine equipment maintenance and replacements


•	Buildings, land and building improvements


•	Pipeline, gathering and other midstream projects


•	Power generation and transmission opportunities


•	Environmental upgrades


•	Other growth opportunities

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

Capital resources

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

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at June 30, 2017:



Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/Revolving credit agreement	(a)	$	175.0		$	25.4	(b)	$	—		5/8/19
Cascade Natural Gas Corporation	Revolving credit agreement		$	75.0	(c)	$	—		$	2.2	(d)	4/24/20
Intermountain Gas Company	Revolving credit agreement		$	85.0	(e)	$	13.5		$	—		4/24/20
Centennial Energy Holdings, Inc.	Commercial paper/Revolving credit agreement	(f)	$	500.0		$	155.7	(b)	$	—		9/23/21


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


(b)	Amount outstanding under commercial paper program.


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


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


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


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

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

The following includes information related to the preceding table.

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

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

The Company's coverage of earnings to fixed charges including preferred stock dividends was 4.0 times, 3.6 times and 3.9 times for the 12 months ended June 30, 2017 and 2016, and December 31, 2016, respectively.

Total equity as a percent of total capitalization was 57 percent, 53 percent and 56 percent at June 30, 2017 and 2016, and December 31, 2016, respectively. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus total equity. This ratio is an indicator of how a company is financing its operations, as well as its financial strength.

Cascade Natural Gas Corporation On April 25, 2017, Cascade amended its revolving credit agreement to increase the borrowing limit from $50.0 million to $75.0 million and extend the termination date from July 9, 2018 to April 24, 2020. The credit agreement contains customary covenants and provisions, including a covenant of Cascade not to permit, at any time, the ratio of

total debt to total capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on indebtedness and the making of certain investments.

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

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

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

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

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

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

Off balance sheet arrangements

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

Contractual obligations and commercial commitments

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

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

New Accounting Standards

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

Critical Accounting Policies Involving Significant Estimates

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Interest rate risk

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

At June 30, 2017, the Company had no outstanding interest rate hedges.

Item 4. Controls and Procedures

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

Evaluation of disclosure controls and procedures

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

Changes in internal controls

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

Part II -- Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

None.

Item 6. Exhibits

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

Signatures

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



		MDU RESOURCES GROUP, INC.

DATE:	August 4, 2017	BY:	/s/ Doran N. Schwartz
			Doran N. Schwartz
			Vice President and Chief Financial Officer


		BY:	/s/ Jason L. Vollmer
			Jason L. Vollmer
			Vice President, Chief Accounting Officer and Treasurer

Exhibit Index



Exhibit No.

+10(a)		MDU Resources Group, Inc. Director Compensation Policy, as amended May 10, 2017*

+10(b)		MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended May 10, 2017, and Rules and Regulations, as amended May 9, 2017*

+10(c)		MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as amended May 10, 2017*

+10(d)		MDU Resources Group, Inc. Supplemental Income Security Plan, as amended and restated May 10, 2017*

+10(e)		Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated April 10, 2017*

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

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

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

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

95		Mine Safety Disclosures*

101		The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.

* Filed herewith.

+ Management contract, compensatory plan or arrangement.

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

(In thousands)

Property, plant and equipment additions in accounts payable