UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For The Quarterly Period Ended ~~September~~June 30, ~~2014~~2015



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 1-3480

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, or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act (Check one):



	Large accelerated filer ý	Accelerated filer o
	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of ~~October 31, 2014: 194,106,937~~July 28, 2015: 195,063,757 shares.

DEFINITIONS

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



Abbreviation or Acronym
~~2013~~2014 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014
AFUDC	Allowance for funds used during construction
ASC	FASB Accounting Standards Codification
ATBs	Atmospheric tower bottoms
Bbl	Barrel
Bicent	Bicent Power LLC
Big Stone Station	475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BLM	Bureau of Land Management
BOE	One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
Bombard Mechanical	Bombard Mechanical, LLC, an indirect wholly owned subsidiary of MDU Construction Services
BOPD	Barrels of oil per day
BPD	Barrels per day
Brazilian Transmission Lines	Company's former investment in ~~the company~~companies owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE were sold in the fourth quarter of 2010 and portions of the ownership interest in ECTE were sold in the third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010)three electric transmission lines
Btu	British thermal unit
California Superior Court	Superior Court of the State of California, County of Los Angeles (South District - Long Beach)
Calumet	Calumet Specialty Products Partners, L.P.
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
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
Clean Water Act	Federal Clean Water Act
Colorado Court of Appeals	Court of Appeals, State of Colorado
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
Connolly-Pacific	Connolly-Pacific Co., an indirect wholly owned subsidiary of Knife River
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 ~~being~~ built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining	Dakota Prairie Refining, LLC, a limited liability company jointly owned by WBI Energy and Calumet
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
~~EBITDA~~	~~Earnings before interest, taxes, depreciation, depletion and amortization~~
~~ECTE~~	Empresa Catarinense de Transmissão de Energia S.A. (2.5 percent ownership interest at September 30, 2014, 2.5, 2.5, 2.5 and 14.99 percent ownership interests were sold in the third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010, respectively)
~~ENTE~~	~~Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)~~
EPA	~~U.S.~~United States Environmental Protection Agency
ERISA	Employee Retirement Income Security Act of 1974
~~ERTE~~	~~Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)~~
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)
FIP	Funding improvement plan
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
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
JTL	JTL Group, Inc., an indirect wholly owned subsidiary of Knife River



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
MATS	Mercury and Air Toxics Standards
MBbls	Thousands of barrels
MBOE	Thousands of BOE
Mcf	Thousand cubic feet
~~MDU Brasil~~	~~MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial Resources~~
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
MEPP	Multiemployer pension plan
MISO	Midcontinent Independent System Operator, Inc.
~~MMBO~~	~~Million barrels of oil~~
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million ~~decatherms~~dk
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana Department of Environmental Quality
Montana First Judicial District Court	Montana First Judicial District Court, Lewis and Clark County
Montana Seventeenth Judicial District Court	Montana Seventeenth Judicial District Court, Phillips County
MPPAA	Multiemployer Pension Plan Amendments Act of 1980
MTPSC	Montana Public Service Commission
MW	Megawatt
NDPSC	North Dakota Public Service Commission
Nevada State District Court	District Court Clark County, Nevada
NGL	Natural gas liquids
NSPS	New Source Performance Standards
NYMEX	New York Mercantile Exchange
Oil	Includes crude oil and condensate
Omimex	Omimex Canada, Ltd.
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PRP	Potentially Responsible Party
psi	Pounds per square inch
RCRA	Resource Conservation and Recovery Act
RIN	Renewable Identification Number
ROD	Record of Decision
RP	Rehabilitation plan
SDPUC	South Dakota Public Utilities Commission
SEC	~~U.S.~~United States Securities and Exchange Commission
SEC Defined Prices	The average price of oil and natural gas during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
Securities Act	Securities Act of 1933, as amended
SourceGas	SourceGas Distribution LLC
South Dakota Supreme Court	Supreme Court of the State of South Dakota
United States District Court for the District of Montana	United States District Court for the District of Montana, Great Falls Division
United States Supreme Court	Supreme Court of the United States
VIE	Variable interest entity
WBI Energy	WBI Energy, Inc., an indirect 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



Wyoming State District Court	District Court of the Fourth Judicial District Within and For Sheridan County, Wyoming
WYPSC	Wyoming Public Service Commission

INTRODUCTION

The Company is a diversified natural resource company, 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, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Oregon and Washington. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added services.

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

In the second quarter of 2015, the Company announced its plan to market Fidelity and exit that line of business. Therefore, the results of Fidelity are reflected in discontinued operations, other than certain general and administrative costs and interest expense which are reflected in the Other category. For more information on the Company's business segments and discontinued operations, see ~~Note 19.~~Notes 9 and 14.

INDEX



Part I -- Financial Information	Page

Consolidated Statements of Income -- Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014	67

Consolidated Statements of Comprehensive Income -- Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014	78

Consolidated Balance Sheets -- ~~September~~June 30, ~~2014~~2015 and ~~2013,~~2014, and December 31, ~~2013~~2014	89

Consolidated Statements of Cash Flows -- ~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014	910

Notes to Consolidated Financial Statements	1011

Management's Discussion and Analysis of Financial Condition and Results of Operations	3235

Quantitative and Qualitative Disclosures About Market Risk	4952

Controls and Procedures	5053

Part II -- Other Information

Legal Proceedings	5053

Risk Factors	5153

Mine Safety Disclosures	5457

Exhibits	5457

Signatures	5558

Exhibit Index	5659

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended						Six Months Ended
	September 30,												June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(In thousands, except per share amounts)												(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	211,536		$	192,103		$	957,769		$	843,670
Exploration and production, construction materials and contracting, construction services and other	1,158,919			1,093,679			2,549,585			2,434,310
Electric, natural gas distribution and regulated pipeline and energy services													$	215,472		$	226,472		$	621,762		$	678,775
Nonregulated pipeline and energy services, construction materials and contracting, construction services and other													770,743			726,092			1,226,802			1,174,551
Total operating revenues	1,370,455			1,285,782			3,507,354			3,277,980			986,215			952,564			1,848,564			1,853,326
Operating expenses:
Fuel and purchased power	19,236			19,983			66,826			59,760			19,327			21,046			43,146			47,590
Purchased natural gas sold	47,718			35,826			377,024			305,268			66,589			82,252			267,739			322,329
Cost of crude oil													44,781			—			47,051			—
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	79,848			64,078			225,180			206,808
Exploration and production, construction materials and contracting, construction services and other	897,887			870,252			2,002,884			1,925,762
Electric, natural gas distribution and regulated pipeline and energy services													70,370			65,348			139,011			131,197
Nonregulated pipeline and energy services, construction materials and contracting, construction services and other													650,188			636,096			1,077,990			1,048,166
Depreciation, depletion and amortization	103,497			99,966			306,180			288,816			54,154			50,381			107,151			100,645
Taxes, other than income	45,504			45,804			150,657			145,784			35,478			35,087			77,478			77,437
Total operating expenses	1,193,690			1,135,909			3,128,751			2,932,198			940,887			890,210			1,759,566			1,727,364
Operating income	176,765			149,873			378,603			345,782			45,328			62,354			88,998			125,962
Loss from equity method investments	(97		)	(61		)	(343		)	(380		)
Other income	2,644			2,326			7,552			5,003			2,320			2,470			2,764			4,638
Interest expense	22,425			21,012			64,912			63,312			23,790			21,484			46,919			42,431
Income before income taxes	156,887			131,126			320,900			287,093			23,858			43,340			44,843			88,169
Income taxes	54,769			46,576			109,818			99,559			9,801			13,894			15,626			27,696
Income from continuing operations	102,118			84,550			211,082			187,534			14,057			29,446			29,217			60,473
Income (loss) from discontinued operations, net of tax (Note 12)	3			(118		)	506			(254		)
Net income	102,121			84,432			211,588			187,280
Income (loss) from discontinued operations, net of tax (Note 9)													(251,415		)	23,881			(576,020		)	48,993
Net income (loss)													(237,358		)	53,327			(546,803		)	109,466
Net loss attributable to noncontrolling interest	(1,088		)	(24		)	(2,390		)	(204		)	(7,754		)	(779		)	(11,282		)	(1,302		)
Dividends declared on preferred stocks	171			171			514			514			171			171			342			342
Earnings on common stock	$	103,038		$	84,285		$	213,464		$	186,970
Earnings (loss) on common stock													$	(229,775	)	$	53,935		$	(535,863	)	$	110,426

Earnings per common share - basic:
Earnings (loss) per common share - basic:
Earnings before discontinued operations	$	.53		$	.45		$	1.11		$	.99		$	.11		$	.16		$	.21		$	.32
Discontinued operations, net of tax	—			—			—			—			(1.29		)	.12			(2.96		)	.26
Earnings per common share - basic	$	.53		$	.45		$	1.11		$	.99
Earnings (loss) per common share - basic													$	(1.18	)	$	.28		$	(2.75	)	$	.58

Earnings per common share - diluted:
Earnings (loss) per common share - diluted:
Earnings before discontinued operations	$	.53		$	.44		$	1.11		$	.99		$	.11		$	.16		$	.21		$	.32
Discontinued operations, net of tax	—			—			—			—			(1.29		)	.12			(2.96		)	.26
Earnings per common share - diluted	$	.53		$	.44		$	1.11		$	.99
Earnings (loss) per common share - diluted													$	(1.18	)	$	.28		$	(2.75	)	$	.58

Dividends declared per common share	$	.1775		$	.1725		$	.5325		$	.5175		$	.1825		$	.1775		$	.3650		$	.3550

Weighted average common shares outstanding - basic	193,949			188,831			191,958			188,831			194,805			192,060			194,643			190,946

Weighted average common shares outstanding - diluted	194,300			189,638			192,307			189,634			194,838			192,659			194,675			191,543

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013
(In thousands)
Net income $ 102,121
$ 84,432
$ 211,588
$ 187,280
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $0 and $0 for the three months ended and $0 and $(3,116) for the nine months ended in 2014 and 2013, respectively —
—
—
(5,594 )
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $50 and $(297) for the three months ended and $264 and $(2,246) for the nine months ended in 2014 and 2013, respectively 82
(510 ) 439
(3,678 )
Net unrealized gain (loss) on derivative instruments qualifying as hedges 82
(510 ) 439
(9,272 )
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $159 and $166 for the three months ended and $477 and $1,027 for the nine months ended in 2014 and 2013, respectively 261
271
781
1,344
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $(89) and $(12) for the three months ended and $(36) and $(209) for the nine months ended in 2014 and 2013, respectively (146 ) (20 ) (58 ) (351 )
Reclassification adjustment for loss on foreign currency translation adjustment included in net income, net of tax of $0 and $70 for the three months ended and $0 and $70 for the nine months ended in 2014 and 2013, respectively —
115
—
143
Foreign currency translation adjustment (146 ) 95
(58 ) (208 )
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(33)and $(5) for the three months ended and $(48) and $(106) for the nine months ended in 2014 and 2013, respectively (62 ) (10 ) (89 ) (197 )
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $16 and $20 for the three months ended and $54 and $63 for the nine months ended in 2014 and 2013, respectively 31
38
100
117
Net unrealized gain (loss) on available-for-sale investments (31 ) 28
11
(80 )
Other comprehensive income (loss) 166
(116 ) 1,173
(8,216 )
Comprehensive income 102,287
84,316
212,761
179,064
Comprehensive loss attributable to noncontrolling interest (1,088 ) (24 ) (2,390 ) (204 )
Comprehensive income attributable to common stockholders $ 103,375
$ 84,340
$ 215,151
$ 179,268



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Net income (loss)	$	(237,358	)	$	53,327		$	(546,803	)	$	109,466
Other comprehensive income:
Net unrealized gain on derivative instruments qualifying as hedges:
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $60 and $60 for the three months ended and $121 and $121 for the six months ended in 2015 and 2014, respectively	100			100			199			199
Reclassification adjustment for (gain) loss on derivative instruments included in income (loss) from discontinued operations, net of tax of $0 and $(50) for the three months ended and $0 and $93 for the six months ended in 2015 and 2014, respectively	—			(87		)	—			158
Net unrealized gain on derivative instruments qualifying as hedges	100			13			199			357
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $420 and $150 for the three months ended and $649 and $318 for the six months ended in 2015 and 2014, respectively	584			245			959			520
Foreign currency translation adjustment:
Foreign currency translation adjustment recognized during the period, net of tax of $6 and $26 for the three months ended and $(63) and $54 for the six months ended in 2015 and 2014, respectively	9			42			(103		)	88
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss), net of tax of $0 and $0 for the three months ended and $491 and $0 for the six months ended in 2015 and 2014, respectively	—			—			802			—
Foreign currency translation adjustment	9			42			699			88
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized gain (loss) on available-for-sale investments arising during the period, net of tax of $(23) and $4 for the three months ended and $(34) and $5 for the six months ended in 2015 and 2014, respectively	(43		)	8			(64		)	10
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $15 and $17 for the three months ended and $34 and $17 for the six months ended in 2015 and 2014, respectively	28			32			64			32
Net unrealized gain (loss) on available-for-sale investments	(15		)	40			—			42
Other comprehensive income	678			340			1,857			1,007
Comprehensive income (loss)	(236,680		)	53,667			(544,946		)	110,473
Comprehensive loss attributable to noncontrolling interest	(7,754		)	(779		)	(11,282		)	(1,302		)
Comprehensive income (loss) attributable to common stockholders	$	(228,926	)	$	54,446		$	(533,664	)	$	111,775

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

September 30, 2014 September 30, 2013 December 31, 2013
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 233,676
$ 66,174
$ 45,225
Receivables, net 784,028
787,311
713,067
Inventories 302,705
314,571
282,391
Deferred income taxes 13,041
26,284
25,048
Commodity derivative instruments 11,322
4,373
1,447
Prepayments and other current assets 72,900
56,257
49,510
Total current assets 1,417,672
1,254,970
1,116,688
Investments 115,656
108,664
112,939
Property, plant and equipment 9,438,609
8,651,334
8,803,866
Less accumulated depreciation, depletion and amortization 4,092,017
3,796,052
3,872,487
Net property, plant and equipment 5,346,592
4,855,282
4,931,379
Deferred charges and other assets:

Goodwill 636,039
636,039
636,039
Other intangible assets, net 10,596
14,092
13,099
Other 247,539
298,061
251,188
Total deferred charges and other assets 894,174
948,192
900,326
Total assets $ 7,774,094
$ 7,167,108
$ 7,061,332
LIABILITIES AND EQUITY

Current liabilities:

Short-term borrowings $ —
$ 7,000
$ 11,500
Long-term debt due within one year 149,101
44,024
12,277
Accounts payable 410,382
437,740
404,961
Taxes payable 105,027
80,392
74,175
Dividends payable 34,607
32,745
33,737
Accrued compensation 66,119
62,746
69,661
Commodity derivative instruments 44
9,740
7,483
Other accrued liabilities 173,247
171,420
171,106
Total current liabilities 938,527
845,807
784,900
Long-term debt 2,061,456
1,967,872
1,842,286
Deferred credits and other liabilities:

Deferred income taxes 887,807
808,011
859,306
Other liabilities 727,801
794,928
718,938
Total deferred credits and other liabilities 1,615,608
1,602,939
1,578,244
Commitments and contingencies

Equity:

Preferred stocks 15,000
15,000
15,000
Common stockholders' equity:

Common stock

Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 194,548,389 at September 30, 2014, 189,369,450 at September 30, 2013 and 189,868,780 at December 31, 2013 194,548
189,369
189,869
Other paid-in capital 1,200,591
1,041,787
1,056,996
Retained earnings 1,713,774
1,546,000
1,603,130
Accumulated other comprehensive loss (37,032 ) (56,937 ) (38,205 )
Treasury stock at cost - 538,921 shares (3,626 ) (3,626 ) (3,626 )
Total common stockholders' equity 3,068,255
2,716,593
2,808,164
Total stockholders' equity 3,083,255
2,731,593
2,823,164
Noncontrolling interest 75,248
18,897
32,738
Total equity 3,158,503
2,750,490
2,855,902
Total liabilities and equity $ 7,774,094
$ 7,167,108
$ 7,061,332

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

~~MDU RESOURCES GROUP, INC.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Nine Months Ended
September 30,
2014 2013
(In thousands)
Operating activities:
Net income $ 211,588
$ 187,280
Income (loss) from discontinued operations, net of tax 506
(254 )
Income from continuing operations 211,082
187,534
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization 306,180
288,816
Loss, net of distributions, from equity method investments 401
1,736
Deferred income taxes 37,006
46,212
Unrealized (gain) loss on commodity derivatives (16,847 ) 5,379
Excess tax benefit on stock-based compensation (4,729 ) —
Changes in current assets and liabilities, net of acquisitions:

Receivables (73,596 ) (107,482 )
Inventories (20,153 ) 1,562
Other current assets (20,416 ) (15,397 )
Accounts payable (22,007 ) 25,817
Other current liabilities 32,767
18,680
Other noncurrent changes (26,915 ) (24,149 )
Net cash provided by continuing operations 402,773
428,708
Net cash provided by discontinued operations 541
254
Net cash provided by operating activities 403,314
428,962

Investing activities:

Capital expenditures (638,731 ) (648,465 )
Acquisitions, net of cash acquired (208,945 ) —
Net proceeds from sale or disposition of property and other 203,386
40,985
Investments 792
218
Proceeds from sale of equity method investment —
1,896
Net cash used in continuing operations (643,498 ) (605,366 )
Net cash provided by discontinued operations —
—
Net cash used in investing activities (643,498 ) (605,366 )

Financing activities:

Issuance of short-term borrowings —
5,000
Repayment of short-term borrowings (11,500 ) —
Issuance of long-term debt 672,351
497,318
Repayment of long-term debt (318,991 ) (255,980 )
Proceeds from issuance of common stock 144,868
—
Dividends paid (102,105 ) (65,660 )
Excess tax benefit on stock-based compensation 4,729
—
Tax withholding on stock-based compensation (5,564 ) —
Contribution from noncontrolling interest 44,900
13,000
Net cash provided by continuing operations 428,688
193,678
Net cash provided by discontinued operations —
—
Net cash provided by financing activities 428,688
193,678
Effect of exchange rate changes on cash and cash equivalents (53 ) (142 )
Increase in cash and cash equivalents 188,451
17,132
Cash and cash equivalents -- beginning of year 45,225
49,042
Cash and cash equivalents -- end of period $ 233,676
$ 66,174



	June 30, 2015			June 30, 2014			December 31, 2014
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	144,372		$	110,817		$	81,855
Receivables, net	627,169			584,658			599,186
Inventories	314,405			318,573			289,410
Deferred income taxes	38,171			22,487			32,012
Prepayments and other current assets	81,355			91,165			83,763
Current assets held for sale	77,292			172,518			131,177
Total current assets	1,282,764			1,300,218			1,217,403
Investments	119,446			116,557			117,883
Property, plant and equipment	6,556,058			5,950,594			6,294,778
Less accumulated depreciation, depletion and amortization	2,444,134			2,325,423			2,386,113
Net property, plant and equipment	4,111,924			3,625,171			3,908,665
Deferred charges and other assets:
Goodwill	635,204			636,039			635,204
Other intangible assets, net	8,506			11,266			9,840
Other	362,407			245,441			322,943
Noncurrent assets held for sale	749,804			1,757,637			1,620,470
Total deferred charges and other assets	1,755,921			2,650,383			2,588,457
Total assets	$	7,270,055		$	7,692,329		$	7,832,408
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	26,000		$	—		$	—
Long-term debt due within one year	418,539			41,646			268,552
Accounts payable	272,988			279,511			279,115
Taxes payable	38,966			37,447			39,955
Dividends payable	35,734			34,388			35,607
Accrued compensation	48,420			44,303			57,402
Other accrued liabilities	164,675			151,762			155,765
Current liabilities held for sale	74,943			231,619			154,728
Total current liabilities	1,080,265			820,676			991,124
Long-term debt	1,958,263			2,144,271			1,825,278
Deferred credits and other liabilities:
Deferred income taxes	753,103			668,497			714,022
Other liabilities	755,742			675,758			756,759
Noncurrent liabilities held for sale	35,790			318,685			295,441
Total deferred credits and other liabilities	1,544,635			1,662,940			1,766,222
Commitments and contingencies
Equity:
Preferred stocks	15,000			15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 195,411,301 at June 30, 2015, 194,138,654 at June 30, 2014 and 194,754,812 at December 31, 2014	195,411			194,139			194,755
Other paid-in capital	1,220,615			1,186,900			1,207,188
Retained earnings	1,155,777			1,645,291			1,762,827
Accumulated other comprehensive loss	(40,246		)	(37,198		)	(42,103		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,527,931			2,985,506			3,119,041
Total stockholders' equity	2,542,931			3,000,506			3,134,041
Noncontrolling interest	143,961			63,936			115,743
Total equity	2,686,892			3,064,442			3,249,784
Total liabilities and equity	$	7,270,055		$	7,692,329		$	7,832,408

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,
	2015			2014
	(In thousands)
Operating activities:
Net income (loss)	$	(546,803	)	$	109,466
Income (loss) from discontinued operations, net of tax	(576,020		)	48,993
Income from continuing operations	29,217			60,473
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	107,151			100,645
Deferred income taxes	24,874			30,516
Excess tax benefit on stock-based compensation	—			(4,729		)
Changes in current assets and liabilities:
Receivables	(37,661		)	18,518
Inventories	(67,604		)	(51,467		)
Other current assets	4,545			(46,003		)
Accounts payable	44,927			(30,741		)
Other current liabilities	(3,426		)	(39,300		)
Other noncurrent changes	(15,602		)	(6,379		)
Net cash provided by continuing operations	86,421			31,533
Net cash provided by discontinued operations	87,312			192,953
Net cash provided by operating activities	173,733			224,486

Investing activities:
Capital expenditures	(355,898		)	(215,970		)
Net proceeds from sale or disposition of property and other	29,550			11,222
Investments	1,208			(1,208		)
Net cash used in continuing operations	(325,140		)	(205,956		)
Net cash used in discontinued operations	(77,238		)	(379,764		)
Net cash used in investing activities	(402,378		)	(585,720		)

Financing activities:
Issuance of short-term borrowings	26,000			—
Repayment of short-term borrowings	—			(11,500		)
Issuance of long-term debt	320,988			441,451
Repayment of long-term debt	(38,137		)	(111,268		)
Proceeds from issuance of common stock	14,499			132,268
Dividends paid	(71,294		)	(67,717		)
Excess tax benefit on stock-based compensation	—			4,729
Tax withholding on stock-based compensation	—			(5,564		)
Contribution from noncontrolling interest	39,500			32,500
Net cash provided by continuing operations	291,556			414,899
Net cash used in discontinued operations	(271		)	(273		)
Net cash provided by financing activities	291,285			414,626
Effect of exchange rate changes on cash and cash equivalents	(123		)	85
Increase in cash and cash equivalents	62,517			53,477
Cash and cash equivalents -- beginning of year	81,855			57,340
Cash and cash equivalents -- end of period	$	144,372		$	110,817

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

~~September~~June 30, ~~2014~~2015 and ~~2013~~2014

(Unaudited)

Note 1 - Basis of presentation

The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's ~~2013~~2014 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. 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 ~~2013~~2014 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after ~~September~~June 30, ~~2014~~2015, up to the date of issuance of these consolidated interim financial statements.

In the second quarter of 2015, the Company announced its plan to market Fidelity, previously referred to as the Company's exploration and production segment, and exit that line of business. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated to present the results of operations of Fidelity as discontinued operations, other than certain general and administrative costs and interest expense which were previously allocated to the former exploration and production segment and do not meet the criteria for income (loss) from discontinued operations. In addition, the assets and liabilities have been treated and classified as held for sale. 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 discontinued operations, see Note 9.

Note 2 - Seasonality of operations

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

Note 3 - Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $~~29.8~~30.3 million, $~~31.1~~26.1 million and $~~36.4~~29.4 million at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, was $~~8.9~~8.6 million, $9.6 million and $~~10.1~~9.5 million, respectively.

Note 4 - Inventories and natural gas in storage

~~Inventories, other than natural gas in storage for the Company's regulated operations, are stated at the lower of average cost or market value.~~ Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. Crude oil and refined products at Dakota Prairie Refinery are carried at lower of cost or market value using the last-in, first-out method. All other inventories are stated at the lower of average cost or market value. The portion of the cost of natural gas in storage expected to be used within one year is included in inventories. Inventories consisted of:


	September 30, 2014		September 30, 2013		December 31, 2013		June 30, 2015		June 30, 2014		December 31, 2014
	(In thousands)						(In thousands)
Aggregates held for resale	$	106,623	$	104,784	$	101,568	$	123,457	$	112,129	$	108,161
Asphalt oil	33,551		43,078		38,099		79,422		76,525		42,135
Materials and supplies	71,515		71,370		69,808		22,594		58,089		54,282
Merchandise for resale	24,566		23,713		21,720		16,140		25,507		24,420
Refined products							16,065		—		—
Natural gas in storage (current)	29,979		37,689		16,417		11,310		10,903		19,302
Crude oil							8,101		—		5,045
Other	36,471		33,937		34,779		37,316		35,420		36,065
Total	$	302,705	$	314,571	$	282,391	$	314,405	$	318,573	$	289,410

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, is included in other assets and was $~~47.4~~49.3 million, $~~48.6~~47.4 million and $~~48.3~~49.3 million at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, respectively.

Note 5 - ~~Oil and natural gas properties disposition~~

Fidelity entered into a purchase and sale agreement on July 17, 2014, to sell certain oil and natural gas properties in Mountrail County, North Dakota. Proceeds from the sale were $184.4 million, subject to final adjustments. The effective date of the disposition was May 1, 2014, with the closing date occurring on September 30, 2014.

~~Note 6 - Impairment of long-lived assets~~

During the second quarter of 2013, the Company recognized an impairment of coalbed natural gas gathering assets at the pipeline and energy services segment of $14.5 million ($9.0 million after tax), which is recorded in operation and maintenance expense on the Consolidated Statements of Income. The impairment is related to coalbed natural gas gathering assets located in Wyoming and Montana where there has been a significant decline in natural gas development and production activity largely due to low natural gas prices. The coalbed natural gas gathering assets were written down to fair value that was determined using the income approach. For more information on this nonrecurring fair value measurement, see Note 16.

~~Note 7 -~~ Earnings (loss) per common share

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


	Three Months Ended		Nine Months Ended		Three Months Ended		Six Months Ended
	September 30,				June 30,
	2014	2013	2014	2013	2015	2014	2015	2014
	(In thousands)				(In thousands)
Weighted average common shares outstanding - basic	193,949	188,831	191,958	188,831	194,805	192,060	194,643	190,946
Effect of dilutive performance share awards	351	807	349	803	33	599	32	597
Weighted average common shares outstanding - diluted	194,300	189,638	192,307	189,634	194,838	192,659	194,675	191,543
Shares excluded from the calculation of diluted earnings per share	—	—	—	—	—	—	—	—

Note 86 - Cash flow information

Cash expenditures for interest and income taxes were as follows:

Nine Months Ended
September 30,
2014
2013
(In thousands)
Interest, net of amounts capitalized and AFUDC - borrowed of $8.6 million and $6.3 million in 2014 and 2013, respectively $ 61,690
$ 60,281
Income taxes paid $ 44,166
$ 30,262



	Six Months Ended
	June 30,
	2015		2014
	(In thousands)
Interest, net of amounts capitalized and AFUDC - borrowed of $5.0 million and $5.7 million in 2015 and 2014, respectively	$	45,102	$	39,384
Income taxes paid, net	$	3,117	$	56,267

Noncash investing transactions were as follows:

September 30,
2014
2013
(In thousands)
Property, plant and equipment additions in accounts payable $ 96,373
$ 85,646

Note 97 - New Accounting ~~Standard~~Standards

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity In April 2014, the FASB issued guidance related to the definition and reporting of discontinued operations. The guidance changed the definition of discontinued operations to include only disposals of a component or group of components that represent a strategic shift and that have a major effect on an entity's operations or financial results. The guidance also expands the disclosure requirements for

transactions that meet the definition of a discontinued operation, and also requires entities to disclose information about individually significant components that are disposed of or held for sale that do not meet the definition of a discontinued operation. This guidance was effective for the Company on January 1, 2015, and is to be applied prospectively for all disposals or components initially classified as held for sale after the effective date, with early adoption permitted. The adoption required additional disclosures for the Company's discontinued operations, however it did not impact the Company's results of operations, financial position or cash flows.

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. This guidance was to be effective for the Company on January 1, 2017. In July 2015, the FASB approved a decision to defer the effective date one year and allow entities to early adopt. With this decision, the guidance will be effective for the Company on January 1, ~~2017.~~2018. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. In addition, the modified approach will require additional disclosures. The Company is evaluating the effects the adoption of the new revenue guidance will have on its results of operations, financial position, cash flows and disclosures, as well as its method of adoption.

Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance on simplifying the presentation of debt issuance costs in the financial statements. This guidance requires entities to present debt issuance costs as a direct deduction to the related debt liability. The amortization of these costs will be reported as interest expense. The guidance will be effective for the Company on January 1, 2016, and is to be applied retrospectively. Early adoption of this guidance is permitted, however the Company has not elected to do so. The guidance will require a reclassification of the debt issuance costs on the Consolidated Balance Sheets, but will not impact the Company's results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) In May 2015, the FASB issued guidance on fair value measurement and disclosure requirements removing the requirement to include investments in the fair value hierarchy for which fair value is measured using the net asset value per share practical expedient. The new guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at net asset value using the practical expedient, and rather limits those disclosures to investments for which the practical expedient have been elected. This guidance will be effective for the Company on January 1, 2016, with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its disclosures, however it will not impact the Company's results of operations, financial position or cash flows.

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 International Financial Reporting Standards. This guidance will be effective for the Company on January 1, 2017, and should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position and cash flows.

1113

Note 108 - Comprehensive income (loss)

The following tables include reclassification adjustments for gains (losses) on derivative instruments qualifying as hedges included in income (loss) from discontinued operations. The after-tax changes in the components of accumulated other comprehensive loss were as follows:


Three Months Ended September 30, 2014	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
Three Months Ended June 30, 2015																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	(3,408	)	$	(33,287	)	$	(579	)	$	76		$	(37,198	)	$	(2,972	)	$	(37,843	)	$	(139	)	$	30		$	(40,924	)
Other comprehensive income (loss) before reclassifications	—			—			(146		)	(62		)	(208		)	—			—			9			(43		)	(34		)
Amounts reclassified from accumulated other comprehensive loss	82			261			—			31			374			100			584			—			28			712
Net current-period other comprehensive income (loss)	82			261			(146		)	(31		)	166			100			584			9			(15		)	678
Balance at end of period	$	(3,326	)	$	(33,026	)	$	(725	)	$	45		$	(37,032	)	$	(2,872	)	$	(37,259	)	$	(130	)	$	15		$	(40,246	)


Three Months Ended September 30, 2013	Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
Three Months Ended June 30, 2014																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain on Available-for-sale Investments		Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	(2,744	)	$	(53,275	)	$	(813	)	$	11		$	(56,821	)	$	(3,421	)	$	(33,532	)	$	(621	)	$	36	$	(37,538	)
Other comprehensive income (loss) before reclassifications	—			—			(20		)	(10		)	(30		)
Other comprehensive income before reclassifications																—			—			42			8		50
Amounts reclassified from accumulated other comprehensive loss	(510		)	272			114			38			(86		)	13			245			—			32		290
Net current-period other comprehensive income (loss)	(510		)	272			94			28			(116		)
Net current-period other comprehensive income																13			245			42			40		340
Balance at end of period	$	(3,254	)	$	(53,003	)	$	(719	)	$	39		$	(56,937	)	$	(3,408	)	$	(33,287	)	$	(579	)	$	76	$	(37,198	)


Nine Months Ended September 30, 2014	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
Six Months Ended June 30, 2015																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)	$	(3,071	)	$	(38,218	)	$	(829	)	$	15		$	(42,103	)
Other comprehensive income (loss) before reclassifications	—			—			(58		)	(89		)	(147		)
Other comprehensive loss before reclassifications																—			—			(103		)	(64		)	(167		)
Amounts reclassified from accumulated other comprehensive loss	439			781			—			100			1,320			199			959			802			64			2,024
Net current-period other comprehensive income (loss)	439			781			(58		)	11			1,173
Net current-period other comprehensive income																199			959			699			—			1,857
Balance at end of period	$	(3,326	)	$	(33,026	)	$	(725	)	$	45		$	(37,032	)	$	(2,872	)	$	(37,259	)	$	(130	)	$	15		$	(40,246	)

1214


Nine Months Ended September 30, 2013	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
Six Months Ended June 30, 2014																Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges			Postretirement Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain on Available-for-sale Investments		Total Accumulated Other Comprehensive Loss
	(In thousands)															(In thousands)
Balance at beginning of period	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)	$	(3,765	)	$	(33,807	)	$	(667	)	$	34	$	(38,205	)
Other comprehensive income (loss) before reclassifications	(5,594		)	—			(351		)	(197		)	(6,142		)
Other comprehensive income before reclassifications																—			—			88			10		98
Amounts reclassified from accumulated other comprehensive loss	(3,678		)	1,344			143			117			(2,074		)	357			520			—			32		909
Net current-period other comprehensive income (loss)	(9,272		)	1,344			(208		)	(80		)	(8,216		)
Net current-period other comprehensive income																357			520			88			42		1,007
Balance at end of period	$	(3,254	)	$	(53,003	)	$	(719	)	$	39		$	(56,937	)	$	(3,408	)	$	(33,287	)	$	(579	)	$	76	$	(37,198	)

Reclassifications out of accumulated other comprehensive loss were as follows:

Three Months Ended Nine Months Ended Location on Consolidated Statements of Income
September 30, September 30,
2014 2013 2014 2013
(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments $ 28
$ 1,007
$ (223 ) $ 6,903
Operating revenues
Interest rate derivative instruments (160 ) (200 ) (480 ) (979 ) Interest expense
(132 ) 807
(703 ) 5,924

50
(297 ) 264
(2,246 ) Income taxes
(82 ) 510
(439 ) 3,678

Amortization of postretirement liability losses included in net periodic benefit cost (420 ) (437 ) (1,258 ) (2,371 ) (a)
159
166
477
1,027
Income taxes
(261 ) (271 ) (781 ) (1,344 )
Reclassification adjustment for loss on foreign currency translation adjustment included in net income —
(185 ) —
(213 ) Earnings (loss) from equity method investments
—
70
—
70
Earnings (loss) from equity method investments
—
(115 ) —
(143 )
Reclassification adjustment for loss on available-for-sale investments included in net income (47 ) (58 ) (154 ) (180 ) Other income
16
20
54
63
Income taxes
(31 ) (38 ) (100 ) (117 )
Total reclassifications $ (374 ) $ 86
$ (1,320 ) $ 2,074



	Three Months Ended						Six Months Ended						Location on Consolidated Statements of Income
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Reclassification adjustment for loss on derivative instruments included in net income (loss):
Interest rate derivative instruments	$	(160	)	$	(160	)	$	(320	)	$	(320	)	Interest expense
	60			60			121			121			Income taxes
	(100		)	(100		)	(199		)	(199		)
Commodity derivative instruments, net of tax	—			87			—			(158		)	Discontinued operations
	(100		)	(13		)	(199		)	(357		)
Amortization of postretirement liability losses included in net periodic benefit cost	(1,004		)	(395		)	(1,608		)	(838		)	(a)
	420			150			649			318			Income taxes
	(584		)	(245		)	(959		)	(520		)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss)	—			—			(1,293		)	—			Other income
	—			—			491			—			Income taxes
	—			—			(802		)	—
Reclassification adjustment for loss on available-for-sale investments included in net income (loss)	(43		)	(49		)	(98		)	(49		)	Other income
	15			17			34			17			Income taxes
	(28		)	(32		)	(64		)	(32		)
Total reclassifications	$	(712	)	$	(290	)	$	(2,024	)	$	(909	)

(a) Included in net periodic benefit cost (credit). For more information, see Note ~~20.~~15.

~~Note 11 - Acquisition~~

On February 10, 2014, the Company entered into agreements to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming. The effective date of the acquisition was October 1, 2013, and the closing occurred on March 6, 2014. The purchase price was $208.9 million, including purchase price adjustments.

The acquisition was accounted for under the acquisition method of accounting and, accordingly, the acquired assets and liabilities assumed have been recorded at their respective fair values as of the date of acquisition. The results of operations of the acquired properties are included in the financial statements since the date of the acquisition. Pro forma financial amounts reflecting the effects of the acquisition are not presented, as such acquisition was not material to the Company's financial position or results of operations.

Note 129 - Discontinued operations

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. The sale of Fidelity is 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 assets and liabilities for these operations have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. 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.

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



	June 30, 2015		June 30, 2014		December 31, 2014
	(In thousands)
ASSETS
Current assets:
Receivables, net	$	33,551	$	146,589	$	94,132
Inventories	6,748		12,849		11,401
Deferred income taxes	—		6,623		—
Commodity derivative instruments	2,537		129		18,335
Prepayments and other current assets	34,456		6,328		7,309
Total current assets held for sale	77,292		172,518		131,177
Noncurrent assets:
Investments	37		37		37
Net property, plant and equipment	1,097,576		1,753,509		1,618,099
Deferred income taxes	52,017		—		—
Other	161		4,091		2,334
Less allowance for impairment of assets held for sale	399,987		—		—
Total noncurrent assets held for sale	749,804		1,757,637		1,620,470
Total assets held for sale	$	827,096	$	1,930,155	$	1,751,647
LIABILITIES
Current liabilities:
Long-term debt due within one year	$	—	$	569	$	897
Accounts payable	49,400		165,189		103,556
Taxes payable	4,064		15,051		19,900
Deferred income taxes	1,401		—		8,206
Accrued compensation	4,460		5,721		5,373
Commodity derivative instruments	3,511		17,449		—
Other accrued liabilities	12,107		27,640		16,796
Total current liabilities held for sale	74,943		231,619		154,728
Noncurrent liabilities:
Long-term debt	—		608		—
Deferred income taxes	—		257,316		238,391
Other liabilities	35,790		60,761		57,050
Total noncurrent liabilities held for sale	35,790		318,685		295,441
Total liabilities held for sale	$	110,733	$	550,304	$	450,169

At the time the Company committed to the plan to sell Fidelity, the Company performed a fair value assessment of the assets and liabilities classified as held for sale. The estimated fair value was determined using the income and the market approaches. The income approach was determined by using the present value of future estimated cash flows. The income approach considered management’s views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry including estimated reserves, estimated prices, market differentials, estimates of well operating and future development costs and timing of operations. The estimated cash flows were discounted using a rate believed to be consistent with those used by principal market participants. The market approach was provided by a third party and based on market transactions involving similar interests in oil and natural gas properties. The fair value assessment indicated an impairment based on the current carrying value exceeding the estimated fair value, which resulted in the Company writing down Fidelity’s assets at June 30, 2015. An impairment of $400.0 million ($252.0 million after tax) was recorded and included in operating expenses from discontinued operations during the second quarter of 2015. The estimated fair value of Fidelity's assets have been categorized as Level 3 in the fair value hierarchy.

Unforeseen events and changes in circumstances and market conditions and material differences in the value of the assets held for sale due to changes in estimates of future cash flows could negatively affect the estimated fair value of Fidelity and result in additional impairment charges. Various factors, including oil and natural gas prices, market differentials, changes in estimates of reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development

costs could result in future impairments of the Company's assets held for sale. In addition, the ultimate sales price of Fidelity may differ from the estimated fair value.

Historically, the Company used the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on the units-of-production method based on total proved reserves.

Prior to the oil and natural gas properties being classified as held for sale, capitalized costs were subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

The Company's capitalized cost under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2015. SEC Defined Prices, adjusted for market differentials, were used to calculate the ceiling test. Accordingly, the Company was required to write down its oil and natural gas producing properties. The Company recorded a $500.4 million ($315.3 million after tax) noncash write-down in operating expenses from discontinued operations in the first quarter of 2015.

In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources agreed to indemnify Bicent and its affiliates from certain third party claims arising out of or in connection with Centennial Resources' ownership or operation of CEM prior to the sale. In addition, Centennial had previously guaranteed CEM's obligations under a construction contract. The Company incurred legal expenses and had a benefit related to the resolution of this matter in the second quarter of 2014, which are reflected in discontinued operations in the consolidated financial statements and accompanying notes. ~~Discontinued operations are included in the Other category.~~

~~Note 13 - Equity method investments~~

~~Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At~~ ~~September 30, 2014~~ ~~and 2013, the Company had no significant equity method investments.~~

~~In August 2006, MDU Brasil acquired ownership interests in~~The reconciliation of the ~~Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern~~major classes of income and ~~southern Brazil. The transmission contracts provide for revenues denominated in~~expense constituting pretax income (loss) from discontinued operations to the ~~Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for~~after-tax net income (loss) from discontinued operations on the ~~Brazilian Transmission Lines is the Brazilian Real.~~Company's Consolidated Statements of Income were as follows:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
	(In thousands)
Operating revenues	$	43,087		$	139,580	$	98,023		$	277,115
Operating expenses	442,725			103,057		1,015,677			201,307
Operating income (loss)	(399,638		)	36,523		(917,654		)	75,808
Other income	188			1,010		2,069			1,025
Interest expense	33			31		55			57
Income (loss) from discontinued operations before income taxes	(399,483		)	37,502		(915,640		)	76,776
Income taxes	(148,068		)	13,621		(339,620		)	27,783
Income (loss) from discontinued operations	$	(251,415	)	$	23,881	$	(576,020	)	$	48,993

In 2009, multiple sales agreements were signed for the Company to sell its ownership interests in the Brazilian Transmission Lines. In November 2010, the Company completed the sale of its entire ownership interest in ENTE and ERTE and ~~59.96~~ percent of the Company's ownership interest in ECTE. The Company's remaining interest in ECTE is being sold over a four-year period. In August 2013 and 2012, and November 2011, the Company completed the sale of one-fourth of the remaining interest in each year. The Company recognized an immaterial gain in 2013. The Company's remaining ownership interest in ECTE is being accounted for under the cost method.

Note 1410 - Goodwill and other intangible assets

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


Nine Months Ended September 30, 2014	Balance as of January 1, 2014*		Goodwill Acquired During the Year		Balance as of September 30, 2014*
Six Months Ended June 30, 2015							Balance as of January 1, 2015*		Goodwill Acquired During the Year		Balance as of June 30, 2015*
	(In thousands)						(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736	$	345,736	$	—	$	345,736
Pipeline and energy services	9,737		—		9,737		9,737		—		9,737
Construction materials and contracting	176,290		—		176,290		176,290		—		176,290
Construction services	104,276		—		104,276		103,441		—		103,441
Total	$	636,039	$	—	$	636,039	$	635,204	$	—	$	635,204

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


Nine Months Ended September 30, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of September 30, 2013*
Six Months Ended June 30, 2014							Balance as of January 1, 2014*		Goodwill Acquired During the Year		Balance as of June 30, 2014*
	(In thousands)						(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736	$	345,736	$	—	$	345,736
Pipeline and energy services	9,737		—		9,737		9,737		—		9,737
Construction materials and contracting	176,290		—		176,290		176,290		—		176,290
Construction services	104,276		—		104,276		104,276		—		104,276
Total	$	636,039	$	—	$	636,039	$	636,039	$	—	$	636,039

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


Year Ended December 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of December 31, 2013*
Year Ended December 31, 2014							Balance as of January 1, 2014*		Goodwill Acquired During the Year/Other			Balance as of December 31, 2014*
	(In thousands)						(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736	$	345,736	$	—		$	345,736
Pipeline and energy services	9,737		—		9,737		9,737		—			9,737
Construction materials and contracting	176,290		—		176,290		176,290		—			176,290
Construction services	104,276		—		104,276		104,276		(835		)	103,441
Total	$	636,039	$	—	$	636,039	$	636,039	$	(835	)	$	635,204

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

Other amortizable intangible assets were as follows:


	September 30, 2014			September 30, 2013			December 31, 2013			June 30, 2015			June 30, 2014			December 31, 2014
	(In thousands)									(In thousands)
Customer relationships	$	21,310		$	21,310		$	21,310		$	20,975		$	21,310		$	21,310
Accumulated amortization	(15,116		)	(13,221		)	(13,726		)	(16,065		)	(14,734		)	(15,556		)
	6,194			8,089			7,584			4,910			6,576			5,754
Noncompete agreements	5,080			6,186			6,186			4,409			5,080			5,080
Accumulated amortization	(4,021		)	(4,706		)	(4,840		)	(3,581		)	(3,936		)	(4,098		)
	1,059			1,480			1,346			828			1,144			982
Other	10,921			10,995			10,995			8,300			10,921			10,921
Accumulated amortization	(7,578		)	(6,472		)	(6,826		)	(5,532		)	(7,375		)	(7,817		)
	3,343			4,523			4,169			2,768			3,546			3,104
Total	$	10,596		$	14,092		$	13,099		$	8,506		$	11,266		$	9,840

Amortization expense for amortizable intangible assets for the three and ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015, was ~~$700,000~~$700,000 and ~~$2.5~~$1.4 million,, respectively. Amortization expense for amortizable intangible assets for the three and ~~nine~~six months ended ~~September~~June 30, ~~2013,~~2014, was ~~$1.2~~$1.0 million and ~~$3.0~~$1.8 million, respectively. Estimated amortization expense for amortizable intangible assets is~~$3.3 million~~ in ~~2014~~, $2.5 million in 2015, $2.2 million in 2016, $1.9 million in 2017, $1.0 million in 2018, $900,000 in 2019 and $~~2.2~~1.4 million thereafter.

Note 1511 - Derivative instruments

The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. As of ~~September~~June 30, ~~2014~~2015, the Company had no outstanding foreign currency or interest rate hedges.

The fair value of derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability.

Fidelity

At ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, Fidelity held oil swap ~~and collar~~ agreements with total forward notional volumes of ~~1.4~~1.1 million, ~~3.9~~2.5 million and ~~2.9 million~~270,000 Bbl, respectively, and natural gas swap agreements with total forward notional volumes of ~~7.3~~1.8 million, ~~16.5~~11.0 million and ~~18.3~~5.0 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production. The gains and losses on the commodity derivative instruments held by Fidelity are included in income (loss) from discontinued operations and the associated assets and liabilities are classified as held for sale.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are ~~both recorded in operating revenues~~ on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments ~~remain~~remained in accumulated other comprehensive income (loss) as of the de-designation date and ~~are~~were reclassified into earnings in future periods as the underlying hedged transactions ~~affect~~affected earnings. ~~At April 1, 2013, accumulated other comprehensive income (loss) included~~ ~~$1.8 million~~ of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date. The Company expects to reclassify into earnings from accumulated other comprehensive income (loss) the remaining value related to de-designating commodity derivative instruments over the next ~~3 months~~.

Prior to April 1, 2013, changes in the fair value attributable to the effective portion of the hedging instruments, net of tax, were recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges were not effective or did not qualify for hedge accounting, the ineffective portion of the changes in fair market value was recorded directly in earnings. Gains and losses on the oil and natural gas derivative instruments were reclassified from accumulated other comprehensive income (loss) into ~~operating revenues~~income (loss) from discontinued operations on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled.

There were no components of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. Gains and losses must be reclassified into earnings as a result of the discontinuance of cash flow hedges if it is probable that the original forecasted transactions will not occur, and there were no such reclassifications.

Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of the derivative instruments in liability positions. The aggregate fair value of Fidelity's derivative instruments with ~~credit-risk-related~~credit-risk related contingent features that ~~are~~were in a liability position at ~~September~~June 30, ~~2014~~2015 and ~~2013,~~2014, were $3.5 million and $17.4 million, respectively. Fidelity had no derivative instruments that were in a liability position with credit-risk-related contingent features at December 31, ~~2013, were $44,000, $9.9 million and $7.5 million, respectively.~~2014. The aggregate fair value of assets that would have been needed to settle

the instruments immediately if the credit-risk-related contingent features were triggered on ~~September~~June 30, ~~2014~~2015 and ~~2013, and December 31, 2013,~~2014, were ~~$44,000, $9.9~~$3.5 million and ~~$7.5~~$17.4 million, respectively.

Centennial

Centennial has historically entered into interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt. As of ~~September~~June 30, ~~2014~~2015 and ~~2013,~~2014, and December 31, ~~2013,~~2014, Centennial had no outstanding interest rate swap agreements.

Fidelity and Centennial

The gains and losses on derivative instruments were as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013
(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax $ —
$ —
$ —
$ (6,153 )
Amount of (gain) loss reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax (18 ) (634 ) 140
(4,349 )
Amount of loss recognized in operating revenues (ineffective portion), before tax —
—
—
(1,422 )

Interest rate derivatives designated as cash flow hedges:
Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax —
—
—
559
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax 100
124
299
671
Amount of loss recognized in interest expense (ineffective portion), before tax —
—
—
(769 )

Commodity derivatives not designated as hedging instruments:
Amount of gain (loss) recognized in operating revenues, before tax 28,755
(12,594 ) 16,847
(3,957 )



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of (gain) loss reclassified from accumulated other comprehensive loss into discontinued operations (effective portion), net of tax	$	—		$	(87	)	$	—		$	158

Interest rate derivatives designated as cash flow hedges:
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	100			100			199			199

Commodity derivatives not designated as hedging instruments:
Amount of loss recognized in discontinued operations, before tax	(8,101		)	(5,196		)	(19,309		)	(11,908		)

Over the next 12 months net losses of approximately $~~553,000~~400,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, as the hedged transactions affect earnings.

The location and fair value of the gross amount of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:


Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at September 30, 2014		Fair Value at September 30, 2013		Fair Value at December 31, 2013		Location on Consolidated Balance Sheets	Fair Value at June 30, 2015		Fair Value at June 30, 2014		Fair Value at December 31, 2014
		(In thousands)							(In thousands)
Not designated as hedges:	Not designated as hedges:							Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	11,322	$	4,373	$	1,447	Current assets held for sale	$	2,537	$	129	$	18,335
	Other assets - noncurrent	259		1,771		503		Noncurrent assets held for sale	—		131		—
Total asset derivatives		$	11,581	$	6,144	$	1,950		$	2,537	$	260	$	18,335


Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at September 30, 2014		Fair Value at September 30, 2013		Fair Value at December 31, 2013		Location on Consolidated Balance Sheets	Fair Value at June 30, 2015		Fair Value at June 30, 2014		Fair Value at December 31, 2014
		(In thousands)							(In thousands)
Not designated as hedges:	Not designated as hedges:							Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	44	$	9,740	$	7,483	Current liabilities held for sale	$	3,511	$	17,449	$	—
	Other liabilities - noncurrent	—		149		—
Total liability derivatives		$	44	$	9,889	$	7,483		$	3,511	$	17,449	$	—

1720

All of the Company's commodity derivative instruments at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, were subject to legally enforceable master netting agreements. However, the Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:


September 30, 2014	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
June 30, 2015								Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)							(In thousands)
Assets:
Commodity derivatives	$	11,581	$	(44	)	$	11,537	$	2,537	$	(2,537	)	$	—
Total assets	$	11,581	$	(44	)	$	11,537	$	2,537	$	(2,537	)	$	—
Liabilities:
Commodity derivatives	$	44	$	(44	)	$	—	$	3,511	$	(2,537	)	$	974
Total liabilities	$	44	$	(44	)	$	—	$	3,511	$	(2,537	)	$	974


September 30, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
June 30, 2014								Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)							(In thousands)
Assets:
Commodity derivatives	$	6,144	$	(4,939	)	$	1,205	$	260	$	(260	)	$	—
Total assets	$	6,144	$	(4,939	)	$	1,205	$	260	$	(260	)	$	—
Liabilities:
Commodity derivatives	$	9,889	$	(4,939	)	$	4,950	$	17,449	$	(260	)	$	17,189
Total liabilities	$	9,889	$	(4,939	)	$	4,950	$	17,449	$	(260	)	$	17,189


December 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
December 31, 2014								Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets		Net
	(In thousands)							(In thousands)
Assets:
Commodity derivatives	$	1,950	$	(1,950	)	$	—	$	18,335	$	—	$	18,335
Total assets	$	1,950	$	(1,950	)	$	—	$	18,335	$	—	$	18,335
Liabilities:
Commodity derivatives	$	7,483	$	(1,950	)	$	5,533
Total liabilities	$	7,483	$	(1,950	)	$	5,533

Note 1612 - 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 $~~63.6~~68.2 million, $~~58.1~~64.4 million and $~~62.4~~65.8 million, at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized ~~loss~~gains on these investments ~~was~~were $~~800,000~~400,000 and $2.4 million for the three ~~months ended September 30, 2014,~~ and ~~the net unrealized gain on these investments was~~ ~~$1.2 million~~ ~~for the~~ ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015, respectively. The net unrealized gains on these investments were ~~$4.1~~$1.1 million and ~~$9.2~~$2.0 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2013,~~2014, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

1821

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:


September 30, 2014	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
June 30, 2015										Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	7,838	$	71	$	(8	)	$	7,901	$	8,072	$	29	$	(28	)	$	8,073
U.S. Treasury securities	2,368		8		(2		)	2,374		2,327		22		—			2,349
Total	$	10,206	$	79	$	(10	)	$	10,275	$	10,399	$	51	$	(28	)	$	10,422


September 30, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
June 30, 2014										Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	8,051	$	70	$	(20	)	$	8,101	$	7,989	$	91	$	(5	)	$	8,075
U.S. Treasury securities	1,912		15		(4		)	1,923		2,066		30		—			2,096
Total	$	9,963	$	85	$	(24	)	$	10,024	$	10,055	$	121	$	(5	)	$	10,171


December 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
December 31, 2014										Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)									(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193	$	6,594	$	60	$	(18	)	$	6,636
U.S. Treasury securities	1,906		15		(4		)	1,917		3,574		—		(19		)	3,555
Total	$	10,057	$	84	$	(31	)	$	10,110	$	10,168	$	60	$	(37	)	$	10,191

The fair value of the Company's money market funds approximates cost.

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 consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. 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.

The estimated fair value of the Company's Level 2 ~~commodity derivative instruments~~RIN obligations are based on the market approach using quoted prices from an independent pricing service. RINs are assigned to biofuels produced or imported into the United States as required by the EPA, which sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the United States. As a producer of diesel fuel, Dakota Prairie Refinery is ~~based upon futures prices, volatility and time~~required to ~~maturity, among other things. Counterparty statements~~blend biofuels into the fuel it produces at a rate that will meet the EPA's quota. RINs are ~~utilized~~purchased in the open market to ~~determine~~satisfy the ~~value of~~requirement as Dakota Prairie Refinery is currently unable to blend biofuels into the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is also evaluated.diesel fuel it produces.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, there were no transfers between Levels 1 and 2.

1922

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



	Fair Value Measurements at June 30, 2015, 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, 2015
	(In thousands)
Assets:
Money market funds	$	—	$	16,358	$	—	$	16,358
Insurance contract*	—		68,187		—		68,187
Available-for-sale securities:
Mortgage-backed securities	—		8,073		—		8,073
U.S. Treasury securities	—		2,349		—		2,349
Total assets measured at fair value	$	—	$	94,967	$	—	$	94,967
Liabilities:
RIN obligations	$	—	$	538	$	—	$	538
Total liabilities measured at fair value	$	—	$	538	$	—	$	538

* The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies, 32 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents.


	Fair Value Measurements at September 30, 2014, Using								Fair Value Measurements at June 30, 2014, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at September 30, 2014		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, 2014
	(In thousands)								(In thousands)
Assets:
Money market funds	$	—	$	19,687	$	—	$	19,687	$	—	$	16,031	$	—	$	16,031
Insurance contract*	—		63,578		—		63,578		—		64,449		—		64,449
Available-for-sale securities:
Mortgage-backed securities	—		7,901		—		7,901		—		8,075		—		8,075
U.S. Treasury securities	—		2,374		—		2,374		—		2,096		—		2,096
Commodity derivative instruments	—		11,581		—		11,581
Total assets measured at fair value	$	—	$	105,121	$	—	$	105,121	$	—	$	90,651	$	—	$	90,651
Liabilities:
Commodity derivative instruments	$	—	$	44	$	—	$	44
Total liabilities measured at fair value	$	—	$	44	$	—	$	44

* The insurance contract invests approximately 21 percent in common stock of mid-cap companies, 1718 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies, 3231 percent in fixed-income investments and 1 percent in cash equivalents.


	Fair Value Measurements at September 30, 2013, Using								Fair Value Measurements at December 31, 2014, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at September 30, 2013		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, 2014
	(In thousands)								(In thousands)
Assets:
Money market funds	$	—	$	21,019	$	—	$	21,019	$	—	$	16,138	$	—	$	16,138
Insurance contract*	—		58,142		—		58,142		—		65,831		—		65,831
Available-for-sale securities:
Mortgage-backed securities	—		8,101		—		8,101		—		6,636		—		6,636
U.S. Treasury securities	—		1,923		—		1,923		—		3,555		—		3,555
Commodity derivative instruments	—		6,144		—		6,144
Total assets measured at fair value	$	—	$	95,329	$	—	$	95,329	$	—	$	92,160	$	—	$	92,160
Liabilities:
Commodity derivative instruments	$	—	$	9,889	$	—	$	9,889
Total liabilities measured at fair value	$	—	$	9,889	$	—	$	9,889

* The insurance contract invests approximately 2920 percent in common stock of mid-cap companies, 2818 percent in common stock of small-cap companies, 2829 percent in common stock of large-cap companies, ~~and~~ 1532 percent in fixed-income ~~investments.~~investments and 1 percent in cash equivalents.

Fair Value Measurements at December 31, 2013, 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, 2013
(In thousands)
Assets:
Money market funds $ —
$ 19,227
$ —
$ 19,227
Insurance contract* —
62,370
—
62,370
Available-for-sale securities:
Mortgage-backed securities —
8,193
—
8,193
U.S. Treasury securities —
1,917
—
1,917
Commodity derivative instruments —
1,950
—
1,950
Total assets measured at fair value $ —
$ 93,657
$ —
$ 93,657
Liabilities:
Commodity derivative instruments $ —
$ 7,483
$ —
$ 7,483
Total liabilities measured at fair value $ —
$ 7,483
$ —
$ 7,483

* The insurance contract invests approximately ~~29 percent~~ ~~in common stock of mid-cap companies,~~ ~~28 percent~~ ~~in common stock of small-cap companies,~~ ~~28 percent~~ ~~in common stock of large-cap companies and~~ ~~15 percent~~ ~~in fixed-income investments.~~

The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill, ~~and oil and natural gas properties,~~ whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable.

During the second quarter of ~~2013,~~2015, coalbed natural gas gathering assets were reviewed for impairment and found to be impaired and were written down to their estimated fair value using the income approach. Under this approach, fair value is determined by using the present value of future estimated cash flows. The factors used to determine the estimated future cash flows include, but are not limited to, internal estimates of gathering revenue, future commodity prices and operating costs and equipment salvage values. The estimated cash flows are discounted using a rate that approximates the weighted average cost of capital of a market participant. These fair value inputs are not typically observable. At June 30, ~~2013,~~2015, coalbed natural gas gathering assets were written down to the nonrecurring fair value measurement of ~~$9.7~~$1.1 million. The fair value of these coalbed natural gas gathering assets have been categorized as Level 3 ~~(Significant Unobservable Inputs)~~ in the fair value hierarchy.

The Company performed a fair value assessment of the assets and liabilities classified as held for sale. For more information on this Level 3 nonrecurring fair value measurement, see Note 9.

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

Carrying
Amount
Fair
Value
(In thousands)
Long-term debt at September 30, 2014 $ 2,210,557
$ 2,332,887
Long-term debt at September 30, 2013 $ 2,011,896
$ 2,106,887
Long-term debt at December 31, 2013 $ 1,854,563
$ 1,912,590



	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at June 30, 2015	$	2,376,802	$	2,468,204
Long-term debt at June 30, 2014	$	2,185,917	$	2,282,174
Long-term debt at December 31, 2014	$	2,093,830	$	2,238,548

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

~~Note 17 - Long-term debt~~

~~On May 8, 2014, the Company amended its revolving credit agreement to increase the borrowing limit to $175.0 million and extend the termination date to May 8, 2019.~~

The Company entered into a $150.0 million note purchase agreement on January 28, 2014, and issued $50.0 million of Senior Notes on April 15, 2014, with a due date of April 15, 2044, at an interest rate of 5.2 percent. The remaining $100.0 million of

2124

~~Senior Notes was issued on July 15, 2014, with due dates ranging from July 15, 2024 to July 15, 2026, at a weighted average interest rate of 4.3 percent.~~

On May 8, 2014, Centennial entered into an amended and restated revolving credit agreement which increased the borrowing limit to $650.0 million and extended the termination date to May 8, 2019. The credit agreement contains customary covenants and provisions, including a covenant of Centennial not to permit, as of the end of any fiscal quarter, the ratio of total consolidated debt to total consolidated capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on subsidiary indebtedness and the making of certain loans and investments.

Centennial's revolving credit agreement contains cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial 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, then Centennial will be in default under the revolving credit agreement.

Centennial entered into two separate two year $125.0 million term loan agreements with variable interest rates on March 31, 2014 and April 2, 2014, respectively. These agreements contain customary covenants and default provisions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of Centennial's total debt to total capitalization to be greater than 65 percent. The covenants also include certain limitations on subsidiary indebtedness and restrictions on the sale of certain assets and on the making of certain loans and investments. On August 6, 2014, Centennial paid all of the outstanding borrowings under one of the two year term loan agreements and all the outstanding borrowings under the remaining two year term loan agreement were paid on October 2, 2014.

~~In addition, borrowings outstanding that were classified as long-term debt under the Company’s and Centennial’s commercial paper programs totaled~~ ~~$293.5 million~~ ~~at September 30, 2014, compared to~~ ~~$153.9 million~~ ~~at December 31, 2013, respectively.~~

Note 1813 - Equity

A summary of the changes in equity was as follows:


Nine Months Ended September 30, 2014	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
Six Months Ended June 30, 2015										Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)									(In thousands)
Balance at December 31, 2013	$	2,823,164		$	32,738		$	2,855,902
Net income (loss)	213,978			(2,390		)	211,588
Balance at December 31, 2014										$	3,134,041		$	115,743		$	3,249,784
Net loss										(535,521		)	(11,282		)	(546,803		)
Other comprehensive income	1,173			—			1,173			1,857			—			1,857
Dividends declared on preferred stocks	(514		)	—			(514		)	(342		)	—			(342		)
Dividends declared on common stock	(102,461		)	—			(102,461		)	(71,078		)	—			(71,078		)
Stock-based compensation	4,257			—			4,257			1,107			—			1,107
Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings	(5,564		)	—			(5,564		)
Net tax benefit on stock-based compensation	4,729			—			4,729
Net tax deficit on stock-based compensation										(1,632		)	—			(1,632		)
Issuance of common stock	144,493			—			144,493			14,499			—			14,499
Contribution from noncontrolling interest	—			44,900			44,900			—			39,500			39,500
Balance at September 30, 2014	$	3,083,255		$	75,248		$	3,158,503
Balance at June 30, 2015										$	2,542,931		$	143,961		$	2,686,892


Nine Months Ended September 30, 2013	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
Six Months Ended June 30, 2014										Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)									(In thousands)
Balance at December 31, 2012	$	2,648,248		$	—		$	2,648,248
Balance at December 31, 2013										$	2,823,164		$	32,738		$	2,855,902
Net income (loss)	187,484			(204		)	187,280			110,768			(1,302		)	109,466
Other comprehensive loss	(8,216		)	—			(8,216		)
Other comprehensive income										1,007			—			1,007
Dividends declared on preferred stocks	(514		)	—			(514		)	(342		)	—			(342		)
Dividends declared on common stock	(97,720		)	—			(97,720		)	(68,025		)	—			(68,025		)
Stock-based compensation	3,730			—			3,730			2,796			—			2,796
Net tax deficit on stock-based compensation	(1,419		)	—			(1,419		)
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings										(5,564		)	—			(5,564		)
Excess tax benefit on stock-based compensation										4,729			—			4,729
Issuance of common stock										131,973			—			131,973
Contribution from noncontrolling interest	—			19,101			19,101			—			32,500			32,500
Balance at September 30, 2013	$	2,731,593		$	18,897		$	2,750,490
Balance at June 30, 2014										$	3,000,506		$	63,936		$	3,064,442

Note 1914 - 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 Company also has an investment in a foreign country, which consists of Centennial Resources' investment in ECTE.~~

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 energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment ~~is constructing~~recently commenced operations of Dakota Prairie Refinery in conjunction with Calumet to refine crude ~~oil~~oil. The facility produces and sells diesel fuel, naphtha and ATBs. This segment also provides cathodic protection and other energy-related services.

The exploration and production segment is engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. For more information regarding this segment, see Note 23.

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 ~~specializes~~provides utility construction services specializing in constructing and maintaining electric and ~~communication~~communications lines, gas pipelines, fire suppression systems, and external lighting and traffic ~~signalization equipment.~~signalization. This segment also provides utility excavation ~~services~~ and inside electrical ~~wiring, cabling~~ and mechanical services, ~~sells and distributes electrical materials,~~ and manufactures and distributes ~~specialty equipment.~~transmission line construction equipment and 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 and pollution liability 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 Fidelity and do not meet the criteria for income (loss) from discontinued operations. The Other category also included Centennial Resources' investment in ~~ECTE.~~the Brazilian Transmission Lines.

Discontinued operations includes the results of Fidelity other than certain general and administrative costs and interest expense as described above. Fidelity is engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. The Company has begun marketing Fidelity and plans to exit that line of business. Discontinued operations also includes legal expenses and a benefit related to the vacation of an arbitration award in 2014 related to Centennial Resources. For more information on discontinued operations, see Note 9.

The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the ~~2013~~2014 Annual Report. Information on the Company's businesses was as follows:


Three Months Ended September 30, 2014	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)								Three Months Ended						Six Months Ended
									June 30,
									2015			2014			2015			2014
									(In thousands)
External operating revenues:
Regulated operations:
Electric	$	68,936	$	—		$	9,162		$	64,265		$	65,149		$	136,041		$	138,796
Natural gas distribution	96,185		—			(12,252		)	132,965			146,077			463,538			520,311
Pipeline and energy services	46,415		4,334			5,060			18,242			15,246			22,183			19,668
	211,536		4,334			1,970			215,472			226,472			621,762			678,775
Exploration and production	147,677		8,130			34,750
Nonregulated operations:
Pipeline and energy services									63,131			16,044			77,834			29,859
Construction materials and contracting									495,640			434,452			701,298			598,875
Construction services									211,515			275,109			446,918			545,002
Other									457			487			752			815
									770,743			726,092			1,226,802			1,174,551
Total external operating revenues									$	986,215		$	952,564		$	1,848,564		$	1,853,326

Intersegment operating revenues:
Regulated operations:
Electric									$	—		$	—		$	—		$	—
Natural gas distribution									—			—			—			—
Pipeline and energy services									6,564			6,937			27,625			24,210
									6,564			6,937			27,625			24,210
Nonregulated operations:
Pipeline and energy services									110			177			316			371
Construction materials and contracting	740,496		6,322			55,218			1,257			8,106			2,205			12,123
Construction services	270,313		16,420			9,876			3,491			7,273			15,186			11,010
Other	433		2,601			2,746			1,792			1,744			3,563			3,468
	1,158,919		33,473			102,590			6,650			17,300			21,270			26,972
Intersegment eliminations	—		(37,807		)	(1,522		)	(13,214		)	(24,237		)	(48,895		)	(51,182		)
Total	$	1,370,455	$	—		$	103,038
Total intersegment operating revenues									$	—		$	—		$	—		$	—

2326

Three Months Ended September 30, 2013
External
Operating
Revenues
Inter-
segment
Operating
Revenues
Earnings
on Common
Stock
(In thousands)
Electric $ 68,314
$ —
$ 11,417
Natural gas distribution 77,417
—
(11,204 )
Pipeline and energy services 46,372
4,906
5,310
192,103
4,906
5,523
Exploration and production 119,234
10,714
17,434
Construction materials and contracting 706,982
7,422
49,159
Construction services 267,038
3,097
12,154
Other 425
1,859
1,217
1,093,679
23,092
79,964
Intersegment eliminations —
(27,998 ) (1,202 )
Total $ 1,285,782
$ —
$ 84,285

Nine Months Ended September 30, 2014
External
Operating
Revenues
Inter-
segment
Operating
Revenues
Earnings
on Common
Stock
(In thousands)
Electric $ 207,732
$ —
$ 28,018
Natural gas distribution 616,496
—
10,516
Pipeline and energy services 133,541
30,497
15,198
957,769
30,497
53,732
Exploration and production 393,653
39,269
74,869
Construction materials and contracting 1,339,371
18,445
42,199
Construction services 815,313
27,431
40,751
Other 1,248
6,069
4,618
2,549,585
91,214
162,437
Intersegment eliminations —
(121,711 ) (2,705 )
Total $ 3,507,354
$ —
$ 213,464


									Three Months Ended						Six Months Ended
Nine Months Ended September 30, 2013	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)								June 30,
									2015			2014			2015			2014
									(In thousands)
Earnings (loss) on common stock:
Regulated operations:
Electric	$	189,949	$	—		$	25,652		$	5,910		$	7,823		$	14,237		$	18,856
Natural gas distribution	536,756		—			15,420			(5,375		)	(4,494		)	16,075			22,768
Pipeline and energy services	116,965		31,623			1,247			4,329			3,614			9,685			6,612
	843,670		31,623			42,319			4,864			6,943			39,997			48,236
Exploration and production	371,648		33,083			70,713
Nonregulated operations:
Pipeline and energy services									(5,933		)	2,175			(7,271		)	3,526
Construction materials and contracting	1,287,305		24,673			38,602			20,136			10,554			5,501			(13,019		)
Construction services	774,103		7,011			36,733			7,003			14,307			11,763			30,875
Other	1,254		5,516			1,862			(3,746		)	(2,971		)	(8,158		)	(6,758		)
	2,434,310		70,283			147,910			17,460			24,065			1,835			14,624
Intersegment eliminations	—		(101,906		)	(3,259		)	(684		)	(954		)	(1,675		)	(1,427		)
Total	$	3,277,980	$	—		$	186,970
Earnings on common stock before income (loss) from discontinued operations									21,640			30,054			40,157			61,433
Income (loss) from discontinued operations, net of tax									(251,415		)	23,881			(576,020		)	48,993
Total earnings (loss) on common stock									$	(229,775	)	$	53,935		$	(535,863	)	$	110,426

Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from exploration and production, construction materials and contracting, construction services and other are all from nonregulated operations.

Note 2015 - 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 for the Company's pension and other postretirement benefit plans were as follows:

Other
Postretirement
Pension Benefits Benefits
Three Months Ended September 30, 2014
2013
2014
2013
(In thousands)
Components of net periodic benefit cost:
Service cost $ 32
$ 39
$ 379
$ 419
Interest cost 4,420
4,062
919
804
Expected return on assets (5,304 ) (4,979 ) (1,154 ) (1,086 )
Amortization of prior service cost (credit) 18
18
(348 ) (364 )
Amortization of net actuarial loss 1,217
1,793
162
327
Net periodic benefit cost (credit), including amount capitalized 383
933
(42 ) 100
Less amount capitalized 27
157
(65 ) 47
Net periodic benefit cost $ 356
$ 776
$ 23
$ 53

Other
Postretirement
Pension Benefits Benefits
Nine Months Ended September 30, 2014
2013
2014
2013
(In thousands)
Components of net periodic benefit cost:
Service cost $ 96
$ 116
$ 1,138
$ 1,257
Interest cost 13,265
12,186
2,701
2,411
Expected return on assets (15,913 ) (14,937 ) (3,463 ) (3,258 )
Amortization of prior service cost (credit) 54
54
(1,044 ) (1,092 )
Amortization of net actuarial loss 3,651
5,373
486
1,405
Net periodic benefit cost (credit), including amount capitalized 1,153
2,792
(182 ) 723
Less amount capitalized 195
425
(55 ) 137
Net periodic benefit cost (credit) $ 958
$ 2,367
$ (127 ) $ 586



							Other
							Postretirement
	Pension Benefits						Benefits
Three Months Ended June 30,	2015			2014			2015			2014
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	46		$	31		$	425		$	380
Interest cost	4,206			4,405			889			924
Expected return on assets	(5,753		)	(5,484		)	(1,223		)	(1,242		)
Amortization of prior service cost (credit)	18			18			(343		)	(348		)
Amortization of net actuarial loss	1,813			1,121			553			6
Curtailment loss	258			—			—			—
Net periodic benefit cost (credit), including amount capitalized	588			91			301			(280		)
Less amount capitalized	53			73			33			(19		)
Net periodic benefit cost (credit)	$	535		$	18		$	268		$	(261	)



							Other
							Postretirement
	Pension Benefits						Benefits
Six Months Ended June 30,	2015			2014			2015			2014
	(In thousands)
Components of net periodic benefit cost (credit):
Service cost	$	86		$	64		$	908		$	759
Interest cost	8,570			8,845			1,803			1,782
Expected return on assets	(11,126		)	(10,609		)	(2,398		)	(2,309		)
Amortization of prior service cost (credit)	36			36			(685		)	(696		)
Amortization of net actuarial loss	3,548			2,434			1,014			324
Curtailment loss	258			—			—			—
Net periodic benefit cost (credit), including amount capitalized	1,372			770			642			(140		)
Less amount capitalized	129			168			62			10
Net periodic benefit cost (credit)	$	1,243		$	602		$	580		$	(150	)

Nonqualified benefit plans

In addition to the qualified plan defined pension benefits reflected in the table, the Company 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 to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for ~~this plan~~these plans for the three and ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015, was $~~1.7~~1.9 million and $~~5.0~~3.6 million, respectively. The Company's net periodic benefit cost for ~~this plan~~these plans for the three and ~~nine~~six months ended ~~September~~June 30, ~~2013,~~2014, was ~~$1.8~~$1.6 million and ~~$5.5~~$3.3 million, respectively.

Multiemployer plans

On September 24, 2014, Knife River provided notice to the Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming that it was withdrawing from the plan effective October 26, 2014. The plan administrator will determine Knife River's withdrawal liability. For the three months ended March 31, 2015, the Company accrued an additional withdrawal liability of approximately $2.4 million (approximately $1.5 million after tax). The total withdrawal liability is currently estimated at $16.4 million (approximately $9.8 million after tax). The assessed withdrawal liability for this plan may be significantly different from the current estimate.

Note 2116 - Regulatory matters and revenues subject to refund

On April 8, 2014, Montana-Dakota submitted a request to the NDPSC to update the environmental cost recovery rider to reflect actual costs incurred through February 2014 and projected costs through June 2015 related to the recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. The NDPSC approved the proposed rider on July 10, 2014, reflecting an annual amount of $8.6 million to be recovered under the rider. The rider was effective with service rendered on and after July 15, 2014.

On February 27, 2014, Montana-Dakota filed an application with the NDPSC for approval of an electric generation resource recovery rider for recovery of Montana-Dakota's investment in the recently constructed 88-MW simple-cycle natural gas turbine and associated facilities near Mandan, ND. Montana-Dakota requested recovery of $7.4 million annually or approximately 4.6 percent above current rates. Advance determination of prudence and a certificate of public convenience and necessity were received from the NDPSC on April 11, 2012. On March 12, 2014, the NDPSC suspended the filing pending

further review. The NDPSC held a hearing regarding this matter on May 28, 2014. On August 20, 2014, the NDPSC approved a settlement agreement reached with the NDPSC staff on May 20, 2014, as amended July 25, 2014, which provides for establishing a generation resource recovery rider and a provision to recover costs associated with a pipeline to the facility through the fuel and purchased power adjustment mechanism. As part of the settlement, the requested recovery for the 88-MW simple-cycle natural gas turbine was established with Montana-Dakota withdrawing the initial rate adjustment and allowing Montana-Dakota the right to file and implement an adjustment within 30 days of filing upon a reasonable showing that the expected return is below a specified return on equity. The settlement also provides for sharing of earnings received by Montana-Dakota in 2014 over a specified return on equity.

On August 11, 2014, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $3.0 million annually or approximately 3.6 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. On February 3, 2015, the MTPSC approved an interim increase of $2.0 million or approximately 2.3 percent, subject to refund, to be effective with service rendered on and after February 6, 2015. On March 18, 2015, Montana-Dakota and the Montana Consumer Counsel filed a settlement agreement that resolved all issues of the application and reflected a natural gas rate increase of $2.5 million annually or approximately 3.0 percent. An amended stipulation reflecting minor changes in rate design was submitted on March 24, 2015. On April 28, 2015, the MTPSC approved the settlement rates to be effective with service rendered on or after May 20, 2015.

On October 3, 2014, Montana-Dakota filed an application with the WYPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $788,000 annually or approximately 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities and the associated operation and maintenance expenses, depreciation and taxes associated with the increase in investment. On April 16, 2015, Montana-Dakota and the Wyoming Office of Consumer Advocate filed a stipulation and agreement that resolved all issues between the parties and reflected a natural gas rate increase of $501,000 annually or approximately 2.6 percent. The WYPSC held a hearing on this matter on May 19, 2015. The WYPSC approved the stipulation and agreement authorizing the rate increase effective with service rendered on and after June 1, 2015.

On December 22, 2014, Montana-Dakota filed an application for advance determination of prudence and a certificate of public convenience and necessity with the NDPSC for the Thunder Spirit Wind project. This project will provide energy, capacity and

renewable energy credits to Montana-Dakota's electric customers in North Dakota, Montana and South Dakota. The NDPSC held a hearing regarding this matter on May 14, 2015. The NDPSC approved the advance determination of prudence and issued a certificate of public convenience and necessity on June 30, 2015.

On February 6, 2015, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $4.3 million annually or approximately 3.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. Montana-Dakota requested an interim increase of $4.3 million or 3.4 percent, subject to refund, of ~~$2.2 million~~which was approved by the NDPSC on March 11, 2015, effective with service rendered on or ~~approximately~~ ~~2.6 percent, which~~after April 7, 2015. A technical hearing has been scheduled for August 31, 2015. This matter is pending before the ~~MTPSC.~~NDPSC.

On ~~October 3, 2014, Montana-Dakota~~March 31, 2015, Cascade filed an application with the ~~WYPSC~~OPUC for a natural gas rate increase. ~~Montana-Dakota~~Cascade requested a total increase of approximately ~~$788,000~~$3.6 million annually or approximately ~~4.1~~5.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities and the associated operation and maintenance expenses, depreciation and taxes associated with the increase in ~~investment.~~investment, as well as environmental remediation expenses. A hearing has been scheduled for October 27-28, 2015.

On ~~October 31, 2013, WBI Energy Transmission~~April 10, 2015, Montana-Dakota submitted a request to the NDPSC to update the electric rate environmental cost recovery rider to reflect actual costs incurred through February 2015 and projected costs through June 2016 related to the recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. The request also includes costs associated with the environmental upgrade required at the Lewis & Clark Station to comply with the EPA's MATS rule. The filing also requests a revision to the environmental cost recovery rider that will allow future recovery of ongoing reagent costs required to meet environmental standards as a monthly adjustment. A total of $8.1 million is requested to be recovered under the adjustment. The NDPSC approved the requested rider to be effective with service rendered on and after July 1, 2015.

On June 24, 2015, Cascade filed an application with the WUTC for a ~~general~~ natural gas rate ~~change~~increase. Cascade requested a total increase of approximately $3.9 million annually or approximately 1.6 percent above current rates. The requested increase includes costs associated with increased infrastructure investment and the associated operating expenses. A public meeting is scheduled for August 27, 2015.

On June 25, 2015, Montana-Dakota filed an application for an electric rate increase with the MTPSC. Montana-Dakota requested a total increase of approximately $11.8 million annually or approximately 21.1 percent above current rates. The increase is necessary to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and maintenance expenses and taxes associated with the increases in investment. Montana-Dakota requested an interim increase of $11.0 million annually, which is pending before the MTPSC.

On June 30, 2015, Montana-Dakota filed an application with the ~~FERC based on~~SDPUC for an electric rate increase. Montana-Dakota requested a total increase of approximately $2.7 million annually or approximately 19.2 percent above current rates. The increase is necessary to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and maintenance expenses and taxes associated with the increases in investment.

On June 30, 2015, Montana-Dakota filed an application for a natural gas rate increase with the SDPUC. Montana-Dakota requested a total increase of approximately $1.5 million annually or approximately 3.1 percent above current rates. The increase is necessary to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes, partially offset by an increase in ~~investments of~~ ~~$312 million, increased operating costs,~~customers and the effect of lower storage and off system volumes. On April 30, 2014, WBI Energy Transmission reached a settlement in principle with FERC Trial Staff and all active parties to resolve the rate case. WBI Energy Transmission filed settlement rates to take effect on an interim basis, effective May 1, 2014, pending final approval of the settlement. On June 4, 2014, WBI Energy Transmission submitted to the FERC an Uncontested Offer of Settlement. On June 11, 2014, the Presiding Administrative Law Judge issued a Certification of Uncontested Settlement recommending FERC approval of the settlement without modification. On August 11, 2014, the FERC issued an order approving the settlement without modification and the resulting rates were approved to be effective May 1, 2014. No parties to the proceeding requested rehearing of the order, which is now final. Based on the adjusted base period volumes filed in the case, the annual increase in revenues is approximately $11.5 million.throughput.

Note 2217 - Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. 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.

The Company had accrued liabilities of ~~$31.9~~$20.7 million, $~~30.8~~32.1 million and $~~29.5~~27.6 million, which include liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, respectively, which include amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

Litigation

Natural Gas Gathering Operations In January 2010, SourceGas filed an application with the Colorado State District Court to compel WBI Energy Midstream to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of WBI Energy Midstream's pipeline gathering systems in Montana. WBI Energy Midstream resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered WBI Energy Midstream into arbitration. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

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

Exploration and Production During the ordinary course of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.

On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and injunctive relief, sought class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. Fidelity reached a court approved settlement of the matter for an amount that is not material.

Construction Materials Until the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation.

Former Employee Litigation On August 6, 2012, a former employee and his spouse filed actions against Connolly-Pacific and others in California Superior Court alleging the former employee contracted acute myelogenous leukemia from exposure to substances while employed as a seaman by the defendants. The plaintiffs ~~request~~sought compensatory damages ~~of approximately~~ ~~$23.8 million~~ plus punitive damages, costs and interest. Connolly-Pacific reached a settlement of the matter for an amount that is ~~contesting the claims and believes it has meritorious defenses to them. Connolly-Pacific will seek insurance coverage for defense costs and any liability incurred in the litigation.~~not material.

~~Natural Gas Gathering Operations~~Construction Services ~~In January 2010, SourceGas filed an application with the Colorado~~Bombard Mechanical is a third-party defendant in litigation pending in Nevada State District Court in which the plaintiff claims damages attributable to ~~compel WBI Energy Midstream~~defects in the construction of a 48 story residential tower built in 2008 for

which Bombard Mechanical performed plumbing and mechanical work as a subcontractor. On March 12, 2015, the plaintiff submitted cost of repair estimates totaling approximately $26 million for alleged defects related to ~~arbitrate a dispute regarding operating pressures~~plumbing and mechanical system defects. Bombard Mechanical is being defended in the action under a ~~natural gas gathering contract on one~~policy of WBI Energy Midstream's pipeline gathering systems in Montana. WBI Energy Midstream resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered WBI Energy Midstream into arbitration. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately ~~$26.6 million~~. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and,insurance subject to ~~final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013, but~~ a ~~decision has not been issued.~~

~~Exploration and Production~~ ~~During the ordinary course~~reservation of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.

On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and injunctive relief, seeks class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. Fidelity believes it has meritorious defenses against class certification and the claims. The Company intends to resolve this matter through settlement or continuation of the Wyoming State District Court litigation.rights.

The Company also is subject to other litigation, and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals are based on the best information available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above issues and other probable and reasonably possible losses in excess of the amounts accrued, while uncertain, will not have a material effect upon the Company's financial position, results of operations or cash flows.

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 $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. 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 administrative action.

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

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ released a ~~staff report~~ROD in ~~September 2014, which recommends~~January 2015 that selected a ~~cleanup~~remediation alternative for the ~~site.~~site as recommended in an earlier staff report. It is not known at this time what share of the cleanup costs will actually be borne by Cascade; however, Cascade anticipates its proportional share could be approximately 50 ~~percent~~. percent. Cascade has accrued ~~$1.7~~$1.7 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 ~~an order~~orders reauthorizing the deferred accounting for the ~~12 months~~12-month periods starting November 30, ~~2013.~~2013 and December 1, 2014.

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 Department of Ecology 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. Cascade has accrued ~~$12.6~~$12.3 million for the remedial investigation, feasibility study and remediation of this site. 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 until the next general rate case. 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 Department of Ecology 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 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 will 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 connection with the sale of the Brazilian Transmission Lines, ~~as discussed in Note 13,~~ Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are 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.

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. ~~There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices.~~ The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at ~~September~~June 30, ~~2014~~2015, expire in ~~the years ranging from 2014 to~~ 2015; however, Fidelity ~~continues~~may continue to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. ~~There were no~~At June 30, 2015, the fixed maximum amounts guaranteed under these agreements aggregated $2.8 million. The amount outstanding by Fidelity was $2.8 million and was reflected on the Consolidated Balance Sheet at ~~September~~June 30, ~~2014~~2015. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.

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, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At ~~September~~June 30, ~~2014~~2015, the fixed maximum amounts guaranteed under these agreements aggregated $~~114.3~~134.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $~~19.4 million~~ in ~~2014~~; ~~$75.1~~43.6 million in 2015; $~~700,000~~14.5 million in 2016; $~~600,000~~1.2 million in 2017; $500,000 in 2018; $~~500,000~~57.4 million in ~~2019;~~2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at ~~September~~June 30, ~~2014~~2015. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At ~~September~~June 30, ~~2014~~2015, the fixed maximum amounts guaranteed under these letters of credit aggregated $~~39.0~~62.5 million. In ~~2014~~2015 and ~~2015~~2016, $~~8.2~~33.7 million and $~~30.8~~28.8 million, respectively, of letters of credit are scheduled to expire. ~~There were~~ no ~~amounts~~The amount outstanding by subsidiaries of the Company under the above letters of credit was

$100,000 and was reflected on the Consolidated Balance Sheet at ~~September~~June 30, ~~2014~~2015. 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.

Centennial and WBI Holdings have guaranteed certain debt obligations of Dakota Prairie Refining. For more information, see Variable interest entities in this note.

WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At ~~September~~June 30, ~~2014~~2015, the fixed maximum amount guaranteed under this agreement was $4.0 million and is scheduled to expire in 2016. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $~~1.0~~1.2 million. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at ~~September~~June 30, ~~2014~~2015, because this intercompany transaction was eliminated in consolidation.

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 and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at ~~September~~June 30, ~~2014~~2015.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At ~~September~~June 30, ~~2014~~2015, approximately $~~387.0~~720.9 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

Variable interest entities

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

Dakota Prairie Refining, LLC On February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $~~300.0~~300 million, under the agreement are $~~150.0~~150 million and $~~75.0~~75 million, respectively. Capital commitments in excess of ~~$300.0~~$300 million are ~~expected to be~~being shared equally between WBI Energy and Calumet. ~~The total project cost is currently estimated at approximately $360 million.~~WBI Energy's and Calumet's cumulative capital contributions as of June 30, 2015, are $234.5 million and $159.5 million, respectively. Dakota Prairie Refining entered into a term loan for project debt financing of $~~75.0~~75 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

On December 1, 2014, Dakota Prairie Refining entered into a $50 million revolving credit agreement with an expiration date of December 1, 2015. Pursuant to the revolving credit agreement, WBI Holdings has guaranteed 50 percent of the credit agreement and Calumet has issued a letter of credit supporting 50 percent of the credit agreement. The credit agreement is used to meet the operational needs of the facility.

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

~~Construction of~~ Dakota Prairie Refinery began in early 2013 and the plant is not yet operational. Therefore, the results of operations of Dakota Prairie Refining did not have a material effect on the Company's Consolidated Statements of Income.has commenced operations. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets were as follows:


	September 30, 2014		September 30, 2013		December 31, 2013		June 30, 2015		June 30, 2014		December 31, 2014
	(In thousands)						(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	16,723	$	23,146	$	4,774	$	845	$	32,283	$	21,376
Accounts receivable	150		1		—		29,639		—		2,759
Inventories							24,166		—		5,311
Other current assets	4,187		25		26		7,887		2,136		4,019
Total current assets	21,060		23,172		4,800		62,537		34,419		33,465
Net property, plant and equipment	314,551		123,297		172,073		431,476		254,079		398,984
Deferred charges and other assets:
Other							5,729		—		3,400
Total deferred charges and other assets							5,729		—		3,400
Total assets	$	335,611	$	146,469	$	176,873	$	499,742	$	288,498	$	435,849
LIABILITIES
Current liabilities:
Short-term borrowings							$	26,000	$	—	$	—
Long-term debt due within one year	$	3,000	$	3,000	$	3,000	3,000		3,000		3,000
Accounts payable	36,541		20,313		8,904		38,339		28,150		55,089
Taxes payable	323		—		5		1,601		225		648
Accrued compensation	617		—		26		649		256		727
Other accrued liabilities	633		363		461		932		494		899
Total current liabilities	41,114		23,676		12,396		70,521		32,125		60,363
Long-term debt	69,000		72,000		72,000		66,000		69,000		69,000
Total liabilities	$	110,114	$	95,676	$	84,396	$	136,521	$	101,125	$	129,363

Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement expiring in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.

The new 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 ~~September~~June 30, ~~2014,~~2015, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, at ~~September~~June 30, ~~2014~~2015, was $~~12.0~~26.1 million.

Note 2318 - Subsequent ~~Events~~Event

On ~~September 24, 2014, Knife River provided notice to~~July 21, 2015, the ~~plan administrator under one~~Company entered into a $75.0 million term loan agreement with a variable interest rate which matures on July 20, 2016. The agreement contains customary covenants and provisions, including a covenant of the ~~multiemployer pension plans~~Company not to ~~which Knife River is~~permit, at any time, the ratio of funded debt to capitalization (on either a ~~party that it was withdrawing from~~consolidated or unconsolidated basis) to be greater than 65 percent. Other covenants include restrictions on the plan effective October 26, 2014. The plan administrator will determine Knife River's withdrawal liability, which the Company currently estimates at approximately $14 million (approximately $8.4 million after tax). Actual withdrawal liability costs may be significantly different.

~~On October 31, 2014, the Company’s board~~sale of ~~directors approved a plan to market the Company’s Fidelity~~certain assets and ~~potentially exit~~ the oil and natural gas exploration and production business. During the marketing and sales process, Fidelity intends to focus on production and continue to develop its acreage. The Company believes that the potential salemaking of ~~the Fidelity assets will allow it to focus on growing its utility, pipeline and construction businesses and lower its overall business-risk profile.~~

certain investments.

3134

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 energy and transportation infrastructure industries 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 ~~non-strategic~~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, ~~and~~ the issuance from time to time of debt and equity ~~securities.~~securities and asset sales. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and its discontinued operations, and certain related business challenges are summarized below. For a summary of the Company's ~~business segments,~~businesses, see Note ~~19.~~14.

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 are 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.

Pipeline and Energy Services

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, investments in and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering ~~transmission~~ and ~~storage~~transmission facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing/refining activities; and expansion of related energy services.

Challenges Challenges for this segment include: energy and refined product price volatility; tight ~~natural gas~~ basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other pipeline and energy services companies.

~~Exploration and Production~~

~~Strategy~~ The Company intends to market and potentially sell its exploration and production business. Until such sale is accomplished, this segment will apply technology and utilize existing expertise to increase production and reserves from existing leaseholds. By optimizing existing operations, this segment is focused on balancing its oil and natural gas commodity mix to maximize profitability.

~~Challenges~~ Risks and uncertainties associated with the marketing and potential sale of the Fidelity assets; volatility in natural gas and oil prices; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; availability of drilling rigs, materials, auxiliary equipment and industry-related field services; utilizing appropriate technologies; inflationary pressure on development and operating costs; irregularities in geological formations; and competition from other exploration and production companies are ongoing challenges for this segment.

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, ~~continue to be a concern.~~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; continue growth through organic and acquisition opportunities; and focusing our 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.

Discontinued Operations

Strategy The Company began the marketing process of Fidelity and plans to exit that line of business. Until such sale is accomplished, Fidelity will apply technology and utilize existing expertise to maintain production from existing leaseholds. By optimizing existing operations, Fidelity is focused on balancing its oil and natural gas commodity mix to maximize profitability.

Challenges Risks and uncertainties associated with the marketing and sale of Fidelity; current oil and natural gas low-price environment; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; utilizing appropriate technologies; inflationary pressure on development and operating costs; irregularities in geological formations; and competition from other exploration and production companies are ongoing challenges for Fidelity.

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 Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the ~~2013~~2014 Annual Report. For more information on ~~each segment's~~ key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements.

3336

Earnings Overview

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


	Three Months Ended						Nine Months Ended						Three Months Ended						Six Months Ended
	September 30,												June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(Dollars in millions, where applicable)												(Dollars in millions, where applicable)
Electric	$	9.2		$	11.4		$	28.0		$	25.7		$	5.9		$	7.8		$	14.2		$	18.9
Natural gas distribution	(12.3		)	(11.2		)	10.5			15.4			(5.4		)	(4.5		)	16.1			22.8
Pipeline and energy services	5.1			5.3			15.2			1.3			(1.6		)	5.8			2.4			10.1
Exploration and production	34.7			17.4			74.9			70.7
Construction materials and contracting	55.2			49.2			42.2			38.6			20.1			10.6			5.5			(13.0		)
Construction services	9.9			12.2			40.8			36.7			7.0			14.3			11.8			30.9
Other	2.7			1.3			4.1			2.1			(3.7		)	(3.0		)	(8.2		)	(6.9		)
Intersegment eliminations	(1.5		)	(1.2		)	(2.7		)	(3.3		)	(.6		)	(1.0		)	(1.7		)	(1.4		)
Earnings before discontinued operations	103.0			84.4			213.0			187.2			21.7			30.0			40.1			61.4
Income (loss) from discontinued operations, net of tax	—			(.1		)	.5			(.2		)	(251.5		)	23.9			(576.0		)	49.0
Earnings on common stock	$	103.0		$	84.3		$	213.5		$	187.0
Earnings per common share – basic:
Earnings (loss) on common stock													$	(229.8	)	$	53.9		$	(535.9	)	$	110.4
Earnings (loss) per common share – basic:
Earnings before discontinued operations	$	.53		$	.45		$	1.11		$	.99		$	.11		$	.16		$	.21		$	.32
Discontinued operations, net of tax	—			—			—			—			(1.29		)	.12			(2.96		)	.26
Earnings per common share – basic	$	.53		$	.45		$	1.11		$	.99
Earnings per common share – diluted:
Earnings (loss) per common share – basic													$	(1.18	)	$	.28		$	(2.75	)	$	.58
Earnings (loss) per common share – diluted:
Earnings before discontinued operations	$	.53		$	.44		$	1.11		$	.99		$	.11		$	.16		$	.21		$	.32
Discontinued operations, net of tax	—			—			—			—			(1.29		)	.12			(2.96		)	.26
Earnings per common share – diluted	$	.53		$	.44		$	1.11		$	.99
Earnings (loss) per common share – diluted													$	(1.18	)	$	.28		$	(2.75	)	$	.58

Three Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 ~~Consolidated earnings~~The Company recognized a consolidated loss of $229.8 million for the quarter ended ~~September~~June 30, ~~2014, increased $18.7~~2015, compared to consolidated earnings of $53.9 million ~~(22 percent)~~ from the comparable prior period largely due to:

~~Unrealized gain on commodity derivatives~~Discontinued operations which had a fair value impairment of ~~$18.1~~the Company's assets held for sale of $252.0 million (after tax) ~~in 2014 compared to an unrealized~~ ; lower average realized commodity prices, excluding gain/loss on commodity ~~derivatives of $7.9 million (after tax) in 2013, a gain of $3.0 million (after tax) resulting from a lower realized commodity derivative loss in 2014 compared to 2013,~~derivatives; and decreased oil production; partially offset by lower ~~average realized oil prices~~depreciation, depletion and amortization expense

A higher operating loss at Dakota Prairie Refinery and an impairment of coalbed natural gas gathering assets of $1.9 million (after tax) at the ~~exploration~~pipeline and ~~production~~energy services business

~~Higher construction~~Lower workloads and margins in the Western region at the construction services business

Partially offsetting these decreases were higher ~~ready-mixed concrete margins and volumes, as well as higher income tax benefits~~earnings on all product lines at the construction materials and contracting ~~business~~

~~Partially offsetting these increases were:~~

Higher selling, general and administrative expense and lower margins in the Western region, offset in part by higher workloads and margins in the Mountain region as well as higher electrical supply sales and margins at the construction services business

~~Higher operation and maintenance expense and higher interest expense at the electric business~~

business.

~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 ~~Consolidated earnings~~The Company recognized a consolidated loss of $535.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2014, increased $26.5~~2015, compared to consolidated earnings of $110.4 million ~~(14 percent)~~ from the comparable prior period largely due to:

~~The absence~~Discontinued operations which had a $315.3 million after-tax noncash write-down of ~~the 2013 natural gas gathering asset impairment of $9.0 million (after tax), as well as higher earnings from the Company's interest in the Pronghorn~~ oil and natural gas properties; a fair value impairment of the Company's assets held for sale of $252.0 million (after tax); lower average realized commodity prices, excluding gain/loss on commodity derivatives; and decreased oil production; partially offset by lower depreciation, depletion and amortization expense and lease operating expenses

A higher operating loss at Dakota Prairie Refinery and an impairment of coalbed natural gas gathering ~~and processing~~ assets of $1.9 million (after tax) at the pipeline and energy services business

~~Increased oil production, higher average realized~~Lower earnings related to decreased retail sales volumes at the natural gas prices and an unrealized gain on commodity derivatives of $10.7 million (after tax) in 2014 compared to an unrealized loss on commodity derivatives of $3.4 million (after tax) in 2013, partially offset by decreased natural gas production, a loss of $11.2 million (after tax) resulting from a higher realized commodity derivative loss in 2014 compared to 2013, higher depreciation, depletion and amortization expense, lower average realized oil prices and higher lease operating expenses at the exploration and productiondistribution business

~~Higher~~Lower workloads and margins in the Western region ~~and higher margins in the Central region~~ at the construction services business

~~Higher aggregate margins and volumes,~~Partially offsetting these decreases were higher ~~ready-mixed concrete volumes and margins, higher asphalt margins and higher income tax benefits, partially offset by lower construction margins~~earnings on all product lines at the construction materials and contracting ~~business~~

Partially offsetting these increases were higher operation and maintenance expense, the absence of the March 2013 $2.8 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business and higher depreciation, depletion and amortization expense; partially offset by higher retail sales margins at the natural gas distribution business.

FINANCIAL AND OPERATING DATA

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

Electric


	Three Months Ended				Nine Months Ended				Three Months Ended				Six Months Ended
	September 30,								June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
	(Dollars in millions, where applicable)								(Dollars in millions, where applicable)
Operating revenues	$	69.0	$	68.3	$	207.8	$	189.9	$	64.3	$	65.1	$	136.0	$	138.8
Operating expenses:
Fuel and purchased power	19.2		20.0		66.8		59.8		19.3		21.1		43.1		47.6
Operation and maintenance	21.4		19.5		60.4		56.4		22.5		20.5		43.6		38.9
Depreciation, depletion and amortization	8.8		8.1		25.9		24.6		9.3		8.5		18.6		17.1
Taxes, other than income	2.8		2.7		8.4		8.4		3.0		2.8		6.1		5.7
	52.2		50.3		161.5		149.2		54.1		52.9		111.4		109.3
Operating income	16.8		18.0		46.3		40.7		10.2		12.2		24.6		29.5
Earnings	$	9.2	$	11.4	$	28.0	$	25.7	$	5.9	$	7.8	$	14.2	$	18.9
Retail sales (million kWh)	769.5		795.2		2,420.0		2,329.4		745.0		721.5		1,652.7		1,650.4
Average cost of fuel and purchased power per kWh	$	.023	$	.024	$	.026	$	.024	$	.024	$	.027	$	.024	$	.027

Three Months Ended~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 Electric earnings decreased ~~$2.2~~$1.9 million ~~(20~~(24 percent) due to:

Higher operation and maintenance expense, which includes ~~$1.5~~$1.3 million (after tax) ~~primarily related~~largely due to higher payroll and benefit-related costs and higher contract services, primarily related to a planned outage at an electric generation station

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

Higher net interest expense, which includes ~~$700,000~~$500,000 (after tax) largely related to higher long-term debt

Partially offsetting these decreases were increased retail sales margins, primarily due to rate recovery of generation upgrades, as well as increased sales volumes of 3 percent, primarily to commercial and industrial customers.

Six Months Ended June 30, 2015 and 2014 Electric earnings decreased $4.7 million (24 percent) due to:

Higher operation and maintenance expense, which includes $3.0 million (after tax) largely due to higher contract services, primarily related to a planned outage at an electric generation station, and higher payroll and benefit-related costs

Higher net interest expense, which includes $1.3 million (after tax) largely related to higher long-term debt

Higher depreciation, depletion and amortization expense of ~~$400,000~~$1.0 million (after tax)~~, primarily related~~ due to increased property, plant and equipment balances

Partially offsetting these decreases were ~~higher~~increased retail sales margins, primarily due to ~~the~~rate recovery of ~~costs of environmental upgrades, reduced in part by decreased sales volumes of 3 percent, primarily to residential customers.~~

~~Nine Months Ended~~ ~~September 30, 2014~~ ~~and~~ ~~2013~~ ~~Electric earnings increased $2.3 million (9 percent) due to:~~

~~Higher retail sales margins, the result of higher rates, primarily due to the recovery of costs of environmental upgrades; and increased sales volumes of 4 percent to all customer classes~~

~~Higher other income, which includes $1.1 million (after tax) largely related to allowance for funds used during construction~~

~~Partially offsetting these increases were:~~

~~Higher operation and maintenance expense, which includes $2.9 million (after tax) primarily related to higher benefit-related costs and contract services~~

~~Higher interest expense, which includes $1.1 million (after tax), as previously discussed~~

~~Higher depreciation, depletion and amortization expense of $800,000 (after tax), as previously discussed~~generation upgrades.

3538

Natural Gas Distribution



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(Dollars in millions, where applicable)
Operating revenues	$	133.0		$	146.1		$	463.5		$	520.3
Operating expenses:
Purchased natural gas sold	73.1			89.1			295.2			346.4
Operation and maintenance	37.4			35.9			75.8			73.8
Depreciation, depletion and amortization	14.7			13.5			29.3			26.8
Taxes, other than income	10.0			9.9			26.6			27.8
	135.2			148.4			426.9			474.8
Operating income (loss)	(2.2		)	(2.3		)	36.6			45.5
Earnings (loss)	$	(5.4	)	$	(4.5	)	$	16.1		$	22.8
Volumes (MMdk):
Sales	13.7			14.7			52.6			60.0
Transportation	35.1			29.9			70.2			69.2
Total throughput	48.8			44.6			122.8			129.2
Degree days (% of normal)*
Montana-Dakota/Great Plains	92		%	109		%	87		%	107		%
Cascade	80		%	78		%	78		%	93		%
Intermountain	86		%	95		%	85		%	96		%
Average cost of natural gas, including transportation, per dk	$	5.34		$	6.05		$	5.61		$	5.77

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

Three Months Ended Nine Months Ended
September 30, September 30,
2014
2013
2014
2013
(Dollars in millions, where applicable)
Operating revenues $ 96.2
$ 77.5
$ 616.5
$ 536.8
Operating expenses:

Purchased natural gas sold 50.0
36.5
396.3
323.5
Operation and maintenance 38.0
35.1
111.8
104.9
Depreciation, depletion and amortization 13.7
12.7
40.6
37.3
Taxes, other than income 7.7
7.3
35.4
32.9
109.4
91.6
584.1
498.6
Operating income (loss) (13.2 ) (14.1 ) 32.4
38.2
Earnings (loss) $ (12.3 ) $ (11.2 ) $ 10.5
$ 15.4
Volumes (MMdk):

Sales 8.8
7.6
68.8
67.7
Transportation 36.9
37.0
106.1
105.6
Total throughput 45.7
44.6
174.9
173.3
Degree days (% of normal)*

Montana-Dakota/Great Plains 88 % 34 % 106 % 101 %
Cascade 64 % 74 % 91 % 92 %
Intermountain 84 % 89 % 96 % 109 %
Average cost of natural gas, including transportation, per dk $ 5.68
$ 4.84
$ 5.76
$ 4.78
* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 The natural gas distribution business experienced a seasonal loss of ~~$12.3~~$5.4 million compared to a seasonal loss of ~~$11.2~~$4.5 million a year ago ~~(a 9~~(20 percent higher loss). The ~~decline~~higher loss was the result of:

Higher operation and maintenance expense, which includes ~~$2.2~~$1.0 million (after tax) largely related to ~~increased~~higher payroll and benefit-related costs

~~The absence of a 2013 favorable resolution of a state income tax matter of $1.0 million (after tax)~~

Higher depreciation, depletion and amortization expense of $700,000 (after tax), primarily resulting from increased property, plant and equipment balances

Higher net interest expense, which includes $500,000 (after tax) largely related to higher long-term debt

Lower other income, which includes $400,000 (after tax) largely related to lower allowance for funds used during construction

Partially offsetting ~~these~~theses decreases were higher retail sales margins, ~~largely~~primarily resulting from ~~approved rate increases effective in late 2013 as well as higher~~ natural gas retail rate increases offset in part by decreased retail sales ~~volumes.~~volumes due to warmer weather.

The pass-through of lower natural gas prices is reflected in the decrease in both sales revenue and purchased natural gas sold.

~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 Natural gas distribution earnings decreased ~~$4.9~~$6.7 million ~~(32 percent)~~ (29 percent) due to:

~~Higher operation and maintenance expense, which includes $4.9 million (after tax) largely~~Lower retail sales margins related to ~~higher payroll and benefit-related costs and higher contract services~~

~~The absence~~decreased retail sales volumes of 12 percent, primarily resulting from significantly warmer weather than last year, partially offset by weather normalization adjustments in certain jurisdictions. Natural gas retail rate increases also partially offset the ~~March 2013 $2.8 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business~~retail sales margin decrease.

Higher depreciation, depletion and amortization expense of ~~$2.1~~$1.5 million (after tax), ~~as previously discussed~~

~~The absence of a 2013 favorable resolution of a state income tax matter of $1.0 million (after tax)~~

~~Partially offsetting these decreases were:~~

primarily resulting from increased property, plant and equipment balances

Higher ~~retail sales margins, largely resulting from approved rate increases effective in late 2013~~

~~Higher other income,~~net interest expense, which includes ~~$1.2 million~~$900,000 (after tax) largely related to ~~allowance for funds used during construction~~higher long-term debt

The pass-through of lower natural gas prices is reflected in the decrease in both sales revenue and purchased natural gas sold.

3639

Pipeline and Energy Services



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015				2014		2015				2014
	(Dollars in millions)
Operating revenues	$	88.0			$	38.4	$	128.0			$	74.1
Operating expenses:
Cost of crude oil	44.8				—		47.1				—
Operation and maintenance	36.7			*	16.9		56.8			*	33.6
Depreciation, depletion and amortization	10.2				7.2		19.0				14.3
Taxes, other than income	3.7				3.4		7.3				6.6
	95.4				27.5		130.2				54.5
Operating income (loss)	(7.4		)		10.9		(2.2		)		19.6
Earnings (loss)	$	(1.6	)	*	$	5.8	$	2.4		*	$	10.1
Transportation volumes (MMdk)	70.9				53.3		138.9				105.8
Natural gas gathering volumes (MMdk)	8.9				9.7		18.3				19.1
Customer natural gas storage balance (MMdk):
Beginning of period	7.2				10.4		14.9				26.7
Net injection (withdrawal)	4.6				1.0		(3.1		)		(15.3		)
End of period	11.8				11.4		11.8				11.4
Refined product sales (MBbls)
Diesel fuel	263				—		263				—
Naphtha	185				—		185				—
ATBs and other	188				—		188				—
Total refined product sales	636				—		636				—

* Reflects an impairment of coalbed natural gas gathering assets of $3.0 million ($1.9 million after tax). For more information, see Note 12.

Three Months Ended Nine Months Ended
September 30, September 30,
2014
2013
2014
2013

(Dollars in millions)
Operating revenues $ 50.7
$ 51.3
$ 164.0
$ 148.6

Operating expenses:
Purchased natural gas sold 9.9
14.0
49.1
42.6

Operation and maintenance 20.7
16.1
54.4
65.3
*
Depreciation, depletion and amortization 7.4
7.1
21.7
22.0

Taxes, other than income 3.4
3.3
9.9
10.3

41.4
40.5
135.1
140.2

Operating income 9.3
10.8
28.9
8.4

Earnings $ 5.1
$ 5.3
$ 15.2
$ 1.3
*
Transportation volumes (MMdk) 60.5
52.1
166.3
129.2

Natural gas gathering volumes (MMdk) 9.6
10.6
28.7
30.5

Customer natural gas storage balance (MMdk):
Beginning of period 11.4
25.2
26.7
43.7

Net injection (withdrawal) 7.0
12.9
(8.3 ) (5.6 )
End of period 18.4
38.1
18.4
38.1

* Reflects an impairment of coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax).

Three Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 Pipeline and energy services ~~earnings decreased $200,000 (5 percent) due to:~~

Higher operation and maintenance expense (excluding Pronghorn-related expense), which includes $1.8 million (after tax) largely higher payroll and benefit-related costs at existing operations and start-up costs related to Dakota Prairie Refinery

~~Lower storage services earnings~~recognized a loss of ~~$900,000 (after tax), largely due to lower average storage balances and lower rates~~

~~Lower earnings of $200,000 (after tax), due to lower volumes transported to storage, offset in large part by increased off-system volumes~~

~~Partially offsetting the earnings decrease were:~~

~~Higher earnings of $1.7 million (after tax) due to increased transportation rates, primarily due to a rate case settlement~~

~~Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, primarily due to higher volumes~~

~~Nine Months Ended September 30, 2014 and 2013~~ ~~Pipeline and energy services recognized earnings of $15.2~~$1.6 million compared to earnings of ~~$1.3~~$5.8 million for the comparable prior period due to:

A higher operating loss related to the Company's portion of Dakota Prairie Refinery upon commencement of operations in May 2015 resulting in higher operation and maintenance expense due to higher start-up costs and higher rail related costs; higher depreciation, depletion and amortization expense; partially offset by refined product sales gross margin. Margins have been negatively impacted by market conditions.

~~Absence~~Higher operation and maintenance expense excluding Dakota Prairie Refinery, which includes $3.9 million (after tax) primarily related to an impairment of ~~the 2013~~coalbed natural gas gathering ~~asset impairment~~assets of ~~$9.0~~$1.9 million (after tax), largely resulting from low natural gas prices, as discussed in Note 12; higher payroll-related costs; and the absence of an insurance settlement in 2014

~~Higher~~Lower gathering and processing earnings ~~from the Company's interest~~of $600,000 (after tax), largely related to lower processing rates offset in ~~the Pronghorn~~part by higher oil and natural gas ~~gathering and~~ processing ~~assets, primarily due to~~volumes

Partially offsetting the earnings decrease was higher ~~volumes and prices~~

~~Higher~~ earnings of ~~$3.5~~$1.8 million (after tax) due to ~~increased~~higher transportation volumes and higher transportation rates, primarily resulting from a rate case settlement under which higher rates went into effect May 1, 2014.

Six Months Ended June 30, 2015 and ~~volumes~~2014 Pipeline and energy services earnings decreased $7.7 million (76 percent) due to:

A higher operating loss related to the Company's portion of Dakota Prairie Refinery, as previously discussed

~~Partially offsetting these increases were:~~

Higher operation and maintenance expense excluding Dakota Prairie Refinery, which includes $4.1 million (after tax), as previously discussed

Lower storage services earnings of ~~$2.2~~$1.0 million (after tax), largely due to lower ~~average storage balances~~withdrawal volumes and lower ~~rates~~average balances

~~Higher operation~~Lower gathering and ~~maintenance expense (excluding the asset impairment and Pronghorn-related expense), which includes $700,000~~processing earnings of $300,000 (after tax) ~~largely related~~, as previously discussed

Partially offsetting the earnings decrease was higher earnings of $4.5 million (after tax) due to higher ~~start-up costs due to Dakota Prairie Refinery, partially offset by lower legal-related costs at existing operations~~

~~Results also reflect higher operating revenues~~transportation volumes and higher ~~purchased natural gas sold, both related to higher natural gas prices.~~

transportation rates, as previously discussed.

3740

~~Exploration~~Construction Materials and ~~Production~~

Contracting

Three Months Ended Nine Months Ended
September 30, September 30,
2014
2013
2014
2013
(Dollars in millions, where applicable)
Operating revenues:
Oil $ 106.4
$ 121.4
$ 347.2
$ 327.3
NGL 6.1
7.6
19.3
21.3
Natural gas 16.3
20.1
68.4
62.5
Realized loss on commodity derivatives (1.8 ) (6.6 ) (18.8 ) (1.0 )
Unrealized gain (loss) on commodity derivatives 28.8
(12.6 ) 16.8
(5.4 )
155.8
129.9
432.9
404.7
Operating expenses:

Operation and maintenance:

Lease operating costs 22.0
20.6
70.0
63.4
Gathering and transportation 3.0
3.5
8.5
12.1
Other 10.5
12.5
34.1
32.9
Depreciation, depletion and amortization 53.0
49.6
155.4
137.8
Taxes, other than income:
Production and property taxes 11.7
13.3
38.8
37.1
Other .1
.2
.8
.9
100.3
99.7
307.6
284.2
Operating income 55.5
30.2
125.3
120.5
Earnings $ 34.7
$ 17.4
$ 74.9
$ 70.7
Production:
Oil (MBbls) 1,251
1,252
3,897
3,571
NGL (MBbls) 170
196
501
588
Natural gas (MMcf) 5,336
7,302
16,369
21,002
Total production (MBOE) 2,309
2,664
7,126
7,659
Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
Oil (per Bbl) $ 85.10
$ 97.00
$ 89.10
$ 91.64
NGL (per Bbl) $ 35.81
$ 39.02
$ 38.54
$ 36.24
Natural gas (per Mcf) $ 3.06
$ 2.75
$ 4.18
$ 2.98
Average realized prices (including realized gain/loss on commodity derivatives):
Oil (per Bbl) $ 83.54
$ 91.03
$ 85.50
$ 91.13
NGL (per Bbl) $ 35.81
$ 39.02
$ 38.54
$ 36.24
Natural gas (per Mcf) $ 3.09
$ 2.87
$ 3.88
$ 3.02
Average depreciation, depletion and amortization rate, per BOE $ 22.10
$ 17.90
$ 20.98
$ 17.25
Production costs, including taxes, per BOE:
Lease operating costs $ 9.54
$ 7.74
$ 9.82
$ 8.28
Gathering and transportation 1.31
1.33
1.19
1.58
Production and property taxes 5.06
4.98
5.45
4.85
$ 15.91
$ 14.05
$ 16.46
$ 14.71



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015			2014
	(Dollars in millions)
Operating revenues	$	496.9	$	442.6	$	703.5		$	611.0
Operating expenses:
Operation and maintenance	433.7		393.4		634.9		*	569.1
Depreciation, depletion and amortization	16.2		17.4		32.7			35.0
Taxes, other than income	11.4		10.6		20.1			18.9
	461.3		421.4		687.7			623.0
Operating income (loss)	35.6		21.2		15.8			(12.0		)
Earnings (loss)	$	20.1	$	10.6	$	5.5	*	$	(13.0	)
Sales (000's):
Aggregates (tons)	6,940		6,971		10,506			9,800
Asphalt (tons)	1,727		1,474		1,959			1,658
Ready-mixed concrete (cubic yards)	988		907		1,564			1,404

*Reflects a MEPP withdrawal liability of approximately $2.4 million ($1.5 million after tax) in 2015. For more information, see Note 15.

Three Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~ ~~Exploration and production earnings increased~~ ~~$17.3 million~~ ~~(99 percent) due to:~~

~~Unrealized gain on commodity derivatives of $18.1 million (after tax) in~~ 2014 ~~compared to an unrealized loss on commodity derivatives of $7.9 million (after tax) in 2013~~

~~A gain of $3.0 million (after tax) resulting from a lower realized commodity derivative loss in 2014 compared to 2013~~

~~Income tax changes, which includes $1.6 million largely the result of higher income tax benefits~~

~~Higher average realized natural gas prices of 11 percent, excluding gain/loss on commodity derivatives~~

~~Lower production taxes of $1.0 million (after tax), largely related to lower oil prices and lower natural gas production~~

~~Partially offsetting these increases were:~~

~~Lower average realized oil prices of 12 percent, excluding gain/loss on commodity derivatives~~

~~Decreased natural gas production of 27 percent, largely due to the sale of non-strategic assets~~

~~Higher depreciation, depletion and amortization expense of $2.1 million (after tax), due to higher depletion rates, partially offset by lower volumes~~

~~Higher lease operating expenses of $900,000 (after tax), primarily in the Paradox Basin~~

~~Nine Months Ended September 30, 2014 and 2013~~ ~~Exploration and production earnings increased $4.2 million (6 percent) due to:~~

~~Increased oil production of 9 percent, primarily related to the Powder River Basin acquisition and drilling activity in the Paradox Basin~~

~~Higher average realized natural gas prices of 40 percent, excluding gain/loss on commodity derivatives~~

~~Unrealized gain on commodity derivatives of $10.7 million (after tax) in 2014 compared to an unrealized loss on commodity derivatives of $3.4 million (after tax) in 2013~~

~~Partially offsetting these increases were:~~

~~Decreased natural gas production of 22 percent, largely due to the sale of non-strategic assets~~

~~A loss of $11.2 million (after tax) resulting from a higher realized commodity derivative loss in 2014 compared to 2013~~

~~Higher depreciation, depletion and amortization expense of $11.1 million (after tax), due to higher depletion rates, partially offset by lower volumes~~

~~Lower average realized oil prices of 3 percent, excluding gain/loss on commodity derivatives~~

~~Higher lease operating expenses of $4.2 million (after tax), primarily in the Paradox Basin and Bakken areas~~

~~Construction Materials and Contracting~~

Three Months Ended Nine Months Ended
September 30, September 30,
2014
2013
2014
2013
(Dollars in millions)
Operating revenues $ 746.8
$ 714.4
$ 1,357.8
$ 1,312.0
Operating expenses:

Operation and maintenance 627.9
600.9
1,197.0
1,148.8
Depreciation, depletion and amortization 17.0
19.0
52.0
56.7
Taxes, other than income 11.8
11.6
30.7
30.7
656.7
631.5
1,279.7
1,236.2
Operating income 90.1
82.9
78.1
75.8
Earnings $ 55.2
$ 49.2
$ 42.2
$ 38.6
Sales (000's):

Aggregates (tons) 10,166
9,902
19,966
19,012
Asphalt (tons) 3,208
3,311
4,866
4,978
Ready-mixed concrete (cubic yards) 1,233
1,132
2,637
2,458

~~Three Months Ended September 30, 2014 and 2013~~ Construction materials and contracting earnings increased ~~$6.0~~$9.5 million ~~(12~~(91 percent) due to:

Higher earnings of ~~$2.1~~$2.5 million (after tax) resulting from higher ~~construction workloads~~asphalt margins and ~~margins~~volumes

Higher earnings of $1.8 million (after tax) resulting from ~~ready-mixed concrete~~higher aggregate margins ~~and volumes~~

~~Income tax changes, which includes $1.4 million largely the result of higher income tax benefits~~

~~Higher earnings resulting from higher asphalt margins~~

~~Nine Months Ended September 30, 2014 and 2013~~ ~~Construction materials and contracting earnings increased $3.6 million (9 percent) due to:~~

Higher earnings of ~~$2.2 million (after tax) resulting from higher aggregate margins and volumes~~

~~Higher earnings of $1.9~~$1.7 million (after tax) resulting from higher ready-mixed concrete ~~volumes~~margins and ~~margins~~volumes

Higher earnings ~~of $1.5 million (after tax) resulting~~ from ~~higher asphalt margins~~

~~Income tax changes, which includes $1.3 million, as previously discussed~~

~~Higher earnings resulting from higher~~ other product line ~~volumes~~margins and ~~margins~~

volumes

Partially offsetting ~~these~~theses increases ~~were:~~

~~Lower earnings of $2.7 million (after tax) resulting from lower construction margins~~

~~Higher selling, general and administrative expense of $2.0 million (after tax), primarily due to~~were higher ~~benefit-related costs~~

~~Construction Services~~

Three Months Ended Nine Months Ended
September 30, September 30,
2014
2013
2014
2013
(In millions)
Operating revenues $ 286.7
$ 270.1
$ 842.8
$ 781.1
Operating expenses:

Operation and maintenance 258.6
238.8
739.2
683.2
Depreciation, depletion and amortization 3.2
3.0
9.6
8.9
Taxes, other than income 8.0
7.3
26.6
25.3
269.8
249.1
775.4
717.4
Operating income 16.9
21.0
67.4
63.7
Earnings $ 9.9
$ 12.2
$ 40.8
$ 36.7

~~Three Months Ended September 30, 2014 and 2013~~ ~~Construction services earnings decreased $2.3 million (19 percent) due to:~~

~~Higher~~ selling, general and administrative expense of $1.9 million (after tax), primarily related to higher payroll-related ~~costs and bad debt expense~~

~~Lower margins in the Western region~~

~~Partially offsetting these decreases were:~~

~~Higher workloads and margins in the Mountain region~~

~~Higher electrical supply sales and margins~~

costs.

~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 Construction ~~services~~materials and contracting recognized earnings ~~increased $4.1~~of $5.5 million ~~(11 percent)~~ compared to a loss of $13.0 million for the comparable prior period. The increase in earnings was due to:

Higher earnings of $4.5 million (after tax) resulting from higher construction revenues and margins due to favorable weather that allowed an early start of the construction season

Higher ~~workloads~~earnings of $4.4 million (after tax) resulting from higher aggregate margins and ~~margins in the Western region and higher margins in the Central region, primarily related to outside work~~volumes

Higher ~~electrical supply sales~~earnings of $4.2 million (after tax) resulting from higher ready-mixed concrete margins and ~~margins~~volumes

Higher earnings of $2.4 million (after tax) resulting from higher asphalt margins and volumes

Higher earnings from other product line margins and volumes

Partially offsetting these increases were higher selling, general and administrative expense of ~~$3.3~~$2.1 million (after tax), primarily related to higher payroll-related ~~costs.~~costs, and a MEPP withdrawal liability of $1.5 million (after tax), as discussed in Note 15.

4041

~~Other~~

Construction Services


	Three Months Ended						Nine Months Ended					Three Months Ended				Six Months Ended
	September 30,											June 30,
	2014			2013			2014		2013			2015		2014		2015		2014
	(In millions)											(In millions)
Operating revenues	$	3.1		$	2.3		$	7.3	$	6.8		$	215.0	$	282.3	$	462.1	$	556.0
Operating expenses:
Operation and maintenance	(1.4		)	(1.4		)	1.0		1.2			191.8		246.5		416.8		480.6
Depreciation, depletion and amortization	.6			.5			1.6		1.5			3.3		3.2		6.7		6.4
Taxes, other than income	—			.1			.1		.2			7.4		8.3		17.3		18.5
	(.8		)	(.8		)	2.7		2.9			202.5		258.0		440.8		505.5
Operating income	3.9			3.1			4.6		3.9			12.5		24.3		21.3		50.5
Income from continuing operations	2.7			1.3			4.1		2.1
Income (loss) from discontinued operations, net of tax	—			(.1		)	.5		(.2		)
Earnings	$	2.7		$	1.2		$	4.6	$	1.9		$	7.0	$	14.3	$	11.8	$	30.9

Three Months Ended ~~September~~June 30, 2015 and 2014 Construction services earnings decreased $7.3 million (51 percent) due to:

Lower workloads and margins in the Western region resulting from substantial completion of significant projects in 2014 and lower margins in the Central region

Lower electrical supply sales and margins as a result of the sale of underperforming assets in the first quarter

Lower equipment sales and rental margins

These decreases were partially offset by lower selling, general and administrative expense of $2.0 million (after tax), primarily related to lower payroll-related costs.

Six Months Ended June 30, 2015 and 2014 ~~2013~~Construction services earnings decreased$19.1 million (62 percent) due to lower workloads and margins in the Western region, as previously discussed, lower margins in the Central region and lower electrical supply sales and margins as a result of the sale of underperforming assets in the first quarter.

Other



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In millions)
Operating revenues	$	2.2		$	2.2		$	4.4		$	4.3
Operating expenses:
Operation and maintenance	4.0			4.0			7.7			8.1
Depreciation, depletion and amortization	.5			.6			1.0			1.1
Taxes, other than income	—			—			.1			—
	4.5			4.6			8.8			9.2
Operating loss	(2.3		)	(2.4		)	(4.4		)	(4.9		)
Loss	$	(3.7	)	$	(3.0	)	$	(8.2	)	$	(6.9	)

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

Three Months Ended June 30, 2015 and 2014 Other ~~earnings~~loss increased ~~$1.5 million, largely~~$700,000, primarily the result of higher income tax expense in 2015 due to income tax benefits resulting from ~~lower income taxes~~favorable resolution of certain tax matters in 2014.

~~Nine~~Six Months Ended ~~September~~June 30, 2015 and 2014 ~~and~~ ~~2013~~Other ~~earnings~~loss increased ~~$2.7~~$1.3 million,, primarily due to a foreign currency translation loss including ~~the~~ effects of the ~~vacation~~sale of ~~an arbitration award which is included~~the Company's remaining interest in ~~discontinued~~the Brazilian Transmission Lines in January 2015.

Discontinued Operations



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
	(In millions)
Income (loss) from discontinued operations before intercompany eliminations, net of tax	$	(251.5	)	$	23.8	$	(576.2	)	$	48.8
Intercompany eliminations	—			.1		.2			.2
Income (loss) from discontinued operations, net of tax	$	(251.5	)	$	23.9	$	(576.0	)	$	49.0

Three Months Ended June 30, 2015 and 2014 Discontinued operations recognized a loss of $251.5 million compared to income of $23.9 million for the comparable prior period due to:

Fair value impairment of the Company's assets held for sale of $252.0 million (after tax), as discussed in Note ~~12,~~9

Lower average realized oil prices of 47 percent, excluding gain/loss on commodity derivatives

Decreased oil production of 36 percent, largely related to the divestment of certain properties in the last half of 2014, normal production declines and deferral of oil drilling activity due to the current low-price environment

Lower average realized gas prices of 57 percent, excluding gain/loss on commodity derivatives

Partially offsetting these decreases were:

Lower depreciation, depletion and amortization expense of $23.1 million (after tax) due to lower depletion rates and volumes and depreciation, depletion and amortization no longer being recorded on assets held for sale

Lower lease operating expenses of $6.5 million (after tax), largely the result of lower cost structures, as well as decreased production, as previously discussed

Lower production taxes of $5.8 million (after tax), largely related to lower oil and natural gas prices and lower oil production

Lower general and administrative expense primarily related to lower payroll-related costs and professional services

Six Months Ended June 30, 2015 and 2014 Discontinued operations recognized a loss of $576.0 million compared to income ~~taxes~~of $49.0 million for the comparable prior period due to:

A noncash write-down of oil and gas properties of $315.3 million (after tax), as discussed in Note 9

Fair value impairment of the Company's assets held for sale of $252.0 million (after tax), as discussed in Note 9

Lower average realized oil prices of 52 percent, excluding gain/loss on commodity derivatives

Decreased oil production of 30 percent, largely related to the divestment of certain properties in the last half of 2014, normal production declines and deferral of oil drilling activity due to the current low-price environment

Lower average realized gas prices of 61 percent, excluding gain/loss on commodity derivatives

Partially offsetting these decreases were:

Lower depreciation, depletion and amortization expense of $27.4 million (after tax) due to lower depletion rates and volumes and depreciation, depletion and amortization no longer being recorded on assets held for sale

Lower lease operating expenses of $11.1 million (after tax), largely the result of lower cost structures, as well as decreased production, as previously ~~discussed.~~discussed

Lower production taxes of $10.7 million (after tax), largely related to lower oil and gas prices and lower production

Lower general and administrative expense primarily related to lower payroll-related costs and professional services

The following table represents key statistics of Fidelity's operations:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
Production:
Oil (MBbls)	874		1,366		1,839		2,646
NGL (MBbls)	108		167		224		331
Natural gas (MMcf)	5,093		5,756		10,047		11,034
Total production (MBOE)	1,831		2,492		3,738		4,816
Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
Oil (per Bbl)	$	48.90	$	93.06	$	43.66	$	90.99
NGL (per Bbl)	$	17.88	$	37.67	$	18.28	$	39.94
Natural gas (per Mcf)	$	1.62	$	3.76	$	1.82	$	4.72
Average realized prices (including realized gain/loss on commodity derivatives):
Oil (per Bbl)	$	45.23	$	87.03	$	49.17	$	86.43
NGL (per Bbl)	$	17.88	$	37.67	$	18.28	$	39.94
Natural gas (per Mcf)	$	1.91	$	3.40	$	2.27	$	4.27
Production costs, including taxes, per BOE:
Lease operating costs	$	7.37	$	9.57	$	8.13	$	9.97
Gathering and transportation	1.51		1.24		1.40		1.13
Production and property taxes	2.73		5.68		2.72		5.63
	$	11.61	$	16.49	$	12.25	$	16.73

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				Nine Months Ended				Three Months Ended				Six Months Ended
	September 30,								June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
	(In millions)								(In millions)
Intersegment transactions:
Operating revenues	$	37.8	$	28.0	$	121.7	$	101.9	$	13.2	$	24.2	$	48.9	$	51.1
Purchased natural gas sold	12.2		14.7		68.4		60.8		6.5		6.9		27.5		24.0
Operation and maintenance	22.9		11.3		48.3		35.7		5.5		15.7		18.6		24.8
Depreciation, depletion and amortization	.2		—		.6		—		.1		—		.1		—
Earnings on common stock	1.5		1.2		2.7		3.3
Income (loss) from continuing operations									.6		1.0		1.7		1.4

For more information on intersegment eliminations, see Note ~~19.~~14.

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, as well as the various important factors listed in ~~Part II,~~ Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the ~~2013~~2014 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.

Adjusted earnings per common share for 2014, diluted, are projected in the range of $1.40 to $1.50, excluding discontinued operations and the unrealized gain of $10.7 million (after tax) on commodity derivatives. Including these adjustments, GAAP earnings guidance for 2014 is in the same range. Unrealized commodity derivatives fair values can fluctuate causing actual GAAP earnings to vary accordingly.

The Company believes that these non-GAAP financial measures are useful because the items excluded are not indicative of the Company's continuing operating results. Also, the Company's management uses these non-GAAP financial measures as indicators for planning and forecasting future periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

~~The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 7 to 10 percent.~~

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

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

~~Estimated gross capital expenditures for 2014 are approximately $1.1 billion. The estimate excludes noncontrolling interest capital expenditures related to Dakota Prairie Refining.~~

~~The Company announced its intent to market and potentially sell its exploration and production company.~~

Electric and natural gas distribution

Rate base growth is projected to be approximately 911 percent compounded annually over the next five years, including plans for an approximate ~~$1.3~~$1.7 billion gross capital investment ~~program.~~program with $437 million planned for 2015. Although a prolonged period of lower commodity prices may slow Bakken-area growth in the future, the Company continues to see strong current growth with increases of 4.5 percent in electric customer counts and 3.3 percent in natural gas customers in the second quarter compared to a year ago in this area.

Regulatory actions

Completed Cases:


◦	On ~~July 10,~~August 11, 2014 and October 3, 2014, the Company filed applications with the MTPSC and WYPSC, respectively, for natural gas rate increases, as discussed in Note 16.

◦

On November 14, 2014, the Company filed an application with the NDPSC for approval to implement the rate adjustment associated with the electric generation resource recovery rider previously approved by the NDPSC. The rider was established to recover costs associated with new generation such as the Heskett III 88-MW natural gas combustion turbine. The NDPSC approved ~~recovery~~a rate adjustment of ~~$8.6~~$5.3 million annually, ~~effective July 15,~~which was implemented January 9, 2015.

◦

On December 22, 2014, the Company filed for advanced determination of prudence with the NDPSC on the Thunder Spirit Wind project, as discussed in Note 16. The Company has an agreement to ~~reflect actual~~purchase the project, which includes 43 wind turbines totaling 107.5 MW of electric generation at a total cost of approximately $220 million including purchase price, internal costs ~~incurred through February 2014~~ and ~~projected costs through June~~AFUDC with approximately $55 million already funded in 2014. ALLETE Clean Energy is developing the project, with an expected completion in December 2015.


◦	On April 10, 2015, ~~for~~the Company filed an update with the NDPSC to the electric rate environmental cost recovery rider, ~~related~~as discussed in Note 16.

Pending Cases:


◦	On February 6, 2015, March 31, 2015 and June 24, 2015, the Company filed applications with the NDPSC, OPUC and WUTC, respectively, for natural gas rate increases, as discussed in Note 16.

◦

On June 25, 2015, the Company filed an application with the MTPSC for an electric rate increase, as discussed in Note 16. The MTPSC has nine months in which to costs resulting from the retrofit required to be installed at the Big Stone Station. The Company's share of the cost for the installation is approximately $90 million and is expected to be complete in 2015. The NDPSC had earlier approved advance determination of prudence for recovery of costsrender a decision on the ~~system. For more information, see~~application.


◦	On June 30, 2015, the Company filed an application with the SDPUC for an electric rate increase, as discussed in Note ~~21.~~16. The SDPUC has six months in which to render a decision on the application.


◦	On June 30, 2015, the Company filed an application with the SDPUC for a natural gas rate increase, as discussed in Note 16. The SDPUC has six months in which to render a decision on the application.

Expected Filings:


◦	The Company expects to file an electric rate case in Wyoming and a natural gas rate case in Minnesota as well as an update to its generation resource recovery rider and transmission tracker in North Dakota.

Growth Projects/Opportunities


◦	Investments of approximately $60 million are being made in 2015 to serve the ongoing growth in the electric and natural gas customer base associated with the Bakken oil development, where customer growth is higher than the national average. This reflects a slightly lower capital expenditure level compared to 2014, anticipating a tempering of economic activity due to lower oil prices.

◦

The Company, along with a partner, expects to build a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The Company’s share of the cost is estimated at approximately $205 million including development costs and substation upgrade costs. The project has been approved as a MISO multivalue project. A route application was filed ~~an application~~in August ~~11, 2014,~~2013 with the ~~MTPSC for~~state of South Dakota and in October 2013 with the state of North Dakota. A route permit was approved July 10, 2014, in North Dakota and August 13, 2014, in South Dakota. The South Dakota route permit was appealed and a ~~natural gas rate increase, as discussed~~district court ruled in ~~Note 21.~~favor of the project. The district court

decision has been appealed to the South Dakota Supreme Court. Approximately 90 percent of the necessary easements have been secured. The Company continues to expect the project to be completed in 2019.

◦

~~On August 20, 2014,~~The Company is pursuing additional generation projects to meet projected capacity requirements, including 19 MW of natural gas generation at the ~~NDPSC approved~~Lewis & Clark Station to be in service later this year and a ~~settlement agreement~~potential partnership for a large scale combined cycle resource targeted to ~~establish a generation resource recovery rider associated~~be online by late 2020 with the 88-MW simple-cycle natural gas turbine and a provision to recover costs associated with a pipeline to the facility through the fuel and purchased power adjustment mechanism. The agreement allows the Company the right to file and implement adjustments if the expected return is below a specified return on equity as well as sharing of earnings in 2014 if earnings exceed the return. The project cost was $77 million and was brought in-service August 5, 2014. The capacity is necessary to meet the requirements of the Company's integrated electric system customers and is a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC. For more information, see Note 21.share being approximately 200 MW.


◦	The Company ~~filed an application October 3, 2014,~~is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with ~~the WYPSC for a natural gas rate increase, as discussed in Note 21.~~company- and customer-owned pipelines designed to serve existing facilities utilizing fuel oil or propane, and to serve new customers.


◦	The Company ~~has planned natural gas rate case filings for Oregon in late 2014 or early 2015 and North Dakota in early 2015. The Company expects to file electric rate cases in Montana and South Dakota in 2015.~~

Investments are being made in 2014 totaling approximately $80 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is substantially higher than the national average.

~~The Company is engaged in a 30-mile, approximately $60 million natural gas line project into the Hanford Nuclear Site in Washington.~~

The Company, along with a partner, expects to build a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The Company’s share of the cost is estimated at approximately $170 million. The project is a MISO multi-value project. A route application was filed in August 2013 with the state of South Dakota and in October 2013 with the state of North Dakota. A route permit was approved in North Dakota on July 10, 2014, and South

~~Dakota on August 13, 2014. The South Dakota route permit has been appealed. The Company continues to expect the project to be complete in 2019.~~

~~The Company is pursuing additional generation projects including renewable resources.~~

The Company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with company- and customer-owned pipeline facilities designed to serve existing facilities served by fuel oil or propane, and to serve new customers.

~~The Company~~ is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.

Montana-Dakota's labor agreement with the International Brotherhood of Electrical Workers was in effect through April 30, 2015, and Cascade's labor agreement with the International Chemical Workers Union was in effect through April 1, 2015, as reported in Items 1 and 2 - Business Properties - General in the 2014 Annual Report. Montana-Dakota's and Cascade's contracts have been ratified and are effective through April 30, 2018, and April 1, 2018, respectively.

Pipeline and energy services

The Company ~~in conjunction with Calumet, formed Dakota Prairie Refining, to develop, build and operate Dakota Prairie Refinery. Construction began~~continues work on the facility in late March 2013 and is near 90 percent complete. When complete, it will process Bakken crude into diesel, which will be marketed within the Bakken region. Other by-products, naphtha and atmospheric tower bottoms, will be railed to other areas. The total project cost estimate is approximately $360 million, with a projected in-service date in late 2014. EBITDAacquiring easements as well as filing its application for ~~the first year of operation is projected to be in the range of $60 million to $80 million, to be shared equally with Calumet.~~

The Company is evaluating the construction of a second 20,000-barrel-per-day diesel topping plant to be located in the Bakken region of North Dakota. A preferred site has been identified and permitting work has begun. A spring 2015 construction start isits planned ~~should the evaluation warrant proceeding with a second plant.~~

~~The Company is developing plans for its~~ Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 MMcf per day to an announced fertilizer plant near Spiritwood, North Dakota. The project ~~cost~~ is estimated to becost approximately $120 million, with an in-service date in 2017. There is an opportunity to expand this pipeline's capacity to serve other customers in eastern North Dakota.

The Company ishas entered into an agreement with an anchor shipper to construct a pipeline to connect the Demicks Lake gas processing plant in ~~the process of pursuing capacity commitments on a proposed 375-mile natural gas pipeline from western~~northwestern North Dakota to ~~northwestern Minnesota to transport~~deliver natural gas ~~to markets in eastern North Dakota, Minnesota, Wisconsin, Michigan and other Midwest markets. The pipeline is expected to provide access to additional markets via interconnections~~into a new interconnect with ~~pipelines owned by Great Lakes Gas Transmission and Viking Gas Transmission in northwestern Minnesota. Initially~~ the ~~pipeline would transport approximately 400 MMcf per day of natural gas and could be expanded to more than 500 MMcf per day. The project investment is~~Northern Border Pipeline. Project costs are estimated to be ~~approximately $650~~$50 million to $60 million.

On August 11, 2014, the FERC issued an order approving settlement of new rates effective May 1, 2014. Based on the adjusted base period volumes filed in the case, the annual increase in revenues is approximately $11.5 million. For more information, see Note 21.

The Company, in conjunction with Calumet, owns Dakota Prairie Refinery. Construction began on the facility in late March 2013 and operations commenced May 4, 2015. The refinery processes Bakken crude oil into diesel, which is marketed within the Bakken region. Other by-products, naphtha and ATBs, are being transported to other areas. The fully-ramped production slate is expected to include approximately 7,000 BPD of diesel, 6,500 BPD of naphtha and 6,000 BPD of ATBs. Diesel and naphtha prices have recently ~~completed connections for~~deteriorated and the ~~Garden Creek II natural gas processing plant in the Bakken.~~local Bakken basis differential has narrowed causing adverse market conditions. The Company is ~~also engaged~~expecting market conditions to improve with projection of meaningful earnings before interest, taxes, depreciation and amortization contributions from the refinery in various natural gas pipeline projects being constructed in 2014, including an expansion of its transmission system to increase capacity to the Black Hills and a now substantially complete 24-mile pipeline and related processing facilities to transport Fidelity's Paradox basin natural gas production. The total cost for these projects is approximately $50 million.2016.

The Company continues to pursue new growth opportunities and expansion of existing facilities and services offered to customers. ~~Energy~~The Company expects energy development to continue to grow long term within its geographic region, ~~is expanding,~~ most notably in the Bakken area, where the Company owns an extensive natural gas pipeline system. ~~Ongoing energy development is expected to continue to provide growth opportunities for this business.~~

~~Exploration and production~~

The Company ~~announced its intent~~plans to ~~market~~invest $1.1 billion of capital related to ongoing energy and ~~potentially sell its exploration and production company.~~

~~The Company expects to spend approximately $610 million in gross capital expenditures in 2014, which will be partially offset by~~industrial development over the ~~completed sales of certain Mountrail County, North Dakota and South Texas assets.~~

For 2014, the Company expects a 3 to 7 percent increase in oil production. NGL production is expected to decline 20 to 25 percent and natural gas production is expected to be 20 to 25 percent lower compared to a year ago. The declines are primarily the result of the divestment of certain non-strategic natural gas-based properties in 2013 and the divestments of

~~certain Mountrail County and South Texas assets this year. The vast majority of the capital program is focused on growing oil production.~~

The Company has a total of three operated drilling rigs deployed on its acreage with one each in the Bakken, Paradox and East Texas areas. There are two or three non-operated rigs deployed on the Company's Powder River Basin acreage.

~~Recently closed sales of certain Mountrail County and South Texas assets included approximately 1,900 BOPD and 4,100 BOEPD.~~

~~Bakken areas~~


◦	The Company owns a total of approximately 105,500 net acres of leaseholds in Mountrail and Stark counties, North Dakota and Richland County, Montana. The Middle Bakken and Three Forks formations are targeted in North Dakota and the Red River formation is targeted in Montana.


◦	~~Capital expenditures are expected to total approximately $125 million in 2014, excluding the proceeds from the completed sale of certain Mountrail County assets.~~


◦	~~Net oil production for the third quarter was approximately 7,500 BOPD.~~


◦	~~The Company is completing new Bakken wells with coil tubing with cemented liners and is seeing good results.~~

~~Paradox Basin, Utah~~


◦	~~The Company owns approximately 140,000 net acres of leaseholds and has an option to earn another 20,000 acres.~~


◦	~~Capital expenditures are expected to total approximately $150 million in 2014.~~


◦	~~Estimated ultimate recoveries have an upper range of 1.7 MMBO per well.~~


◦	~~Artificial lift facilities have recently been installed on the higher rate Cane Creek Unit 12-1 and 18-1 wells. The combined producing rate is 600 to 800 BOPD.~~


◦	~~Net oil production for third quarter was approximately 2,400 BOPD, up 5 percent from third quarter 2013.~~


◦	Recently drilled wells have yielded lower than expected results and include tighter rock than the previous drilled high rate wells. As a result, in November 2014 the Company will test-fracture stimulation a well for the first time in the basin.

~~Powder River Basin, Wyoming~~


◦	~~In March 2014, the Company acquired approximately 24,500 net acres of leaseholds in Converse County, Wyoming.~~


◦	~~Capital expenditures are expected to total approximately $260 million in 2014, including acquisition costs, related closing adjustments and drilling capital.~~


◦	~~Net production for the third quarter was 1,685 BOEPD (75 percent oil), up 3 percent from late March 2014 average net production of 1,630 BOEPD.~~

Earnings guidance reflects estimated average NYMEX index prices for November through December in the range of $80 to $85 per Bbl of crude oil, and $3.75 to $4.25 per Mcf of natural gas. Estimated prices for NGL are in the range of $20 to $25 per Bbl.

~~Derivatives:~~


◦	~~For October through December 2014, 12,000 BOPD at a weighted average price of $97.50.~~


◦	~~For October through December 2014, 40,000 MMBtu of natural gas per day at a weighted average price of $4.10.~~


◦	~~For January through March 2015, 3,000 BOPD at a weighted average price of $98.00.~~


◦	~~For 2015, 10,000 MMBtu of natural gas per day at a weighted average price of $4.28.~~


◦	~~The commodity derivative instruments that are in place as of October 31, 2014, are summarized in the following chart:~~

Commodity Type Index Period
Outstanding Forward Notional Volume
(Bbl/MMBtu) Price
(Per Bbl/MMBtu)
Crude Oil Swap NYMEX 10/14 - 12/14 92,000 $94.05
Crude Oil Swap NYMEX 10/14 - 12/14 92,000 $94.25
Crude Oil Swap NYMEX 10/14 - 12/14 184,000 $95.00
Crude Oil Swap NYMEX 10/14 - 12/14 92,000 $95.25
Crude Oil Swap NYMEX 10/14 - 12/14 184,000 $96.00
Crude Oil Swap NYMEX 10/14 - 12/14 276,000 $100.50
Crude Oil Swap NYMEX 10/14 - 12/14 184,000 $101.50
Crude Oil Swap NYMEX 1/15 - 3/15 270,000 $98.00
Natural Gas Swap NYMEX 10/14 - 12/14 1,840,000 $4.13
Natural Gas Swap NYMEX 10/14 - 12/14 920,000 $4.05
Natural Gas Swap NYMEX 10/14 - 12/14 920,000 $4.10
Natural Gas Swap NYMEX 1/15 - 12/15 3,650,000 $4.28
next five years.

Construction materials and contracting

Approximate work backlog as of ~~September~~June 30, ~~2014,~~2015, was ~~$476~~$833 million, compared to ~~$525~~$764 million a year ago. Private work represents 139 percent of construction backlog and public work represents 8791 percent of backlog. ~~Bidding opportunities are strong and additional backlog has been secured since September 30, 2014.~~ The backlog includes a variety of projects such as highway grading, paving and underground projects, airports, bridge work and subdivisions.

The Company's approximate backlog in North Dakota as of September 30, 2014, was $64 million. North Dakota backlog was $156 million a year ago, which included the $55 million bypass project in the Bakken region. It was the largest project in the Company's history and is now substantially complete.

Projected revenues included in the Company's ~~2014~~2015 earnings guidance are in the range of ~~$1.7~~$1.8 billion to ~~$1.8~~$2.0 billion.

The Company anticipates margins in ~~2014~~2015 to be ~~in line with 2013~~higher compared to 2014 margins.

~~The Company anticipates recording a withdrawal liability related to a multiemployer pension plan in the fourth quarter 2014. For more information, see Note 23.~~

The Company continues to pursue opportunities for expansion in energy projects such as ~~refineries,~~petrochemical, transmission, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets.

As the country's fifth-largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

Of the ~~seven~~four labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business ~~and~~ Properties - General in the ~~2013~~2014 Annual Report, ~~six~~three have been ratified. The one remaining contract is still in ~~negotiation.~~negotiations.

Construction services

Approximate work backlog as of ~~September~~June 30, ~~2014,~~2015, was ~~$348~~$429 million, compared to ~~$433~~$386 million a year ago. ~~Bidding opportunities are strong and additional backlog has been secured since September 30, 2014.~~ The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including ~~refinery~~petrochemical work.

~~The Company had no backlog in North Dakota as of September 30, 2014. North Dakota backlog was $1 million a year ago.~~

Projected revenues included in the Company's ~~2014~~2015 earnings guidance are in the range of ~~$1.1 billion~~$850 million to ~~$1.2 billion.~~$950 million.

The Company anticipates margins in ~~2014~~2015 to be ~~in line with 2013~~lower compared to 2014 margins.

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

Discontinued operations

The Company intends to sell Fidelity and although an actual closing date is unknown, for forecasting purposes the Company is assuming a sale transaction by year end 2015.

During 2015, the Company plans to continue to focus on maximizing the value of Fidelity, including focusing on lowering its cost structure beyond the 25 percent general and administrative cost reduction already in place.

The Company expects to spend approximately $100 million in capital expenditures in 2015, operating within projected cash flows. The Company currently has no rigs drilling on its operated properties.

Key activities for 2015 include:


◦	Commissioning and start-up of the gas gathering and processing facilities in the Paradox Basin.


◦	Fracture stimulate two wells in the Paradox Basin.


◦	Completion of a backlog of wells in the non-operated Powder River Basin.


◦	Completion of 2014 activity carryover in the Bakken.


◦	No additional drilling of horizontal wells in East Texas is planned in the current low natural gas price environment.

Operational updates:


◦	The Cane Creek Unit 28-3 well (100 percent working interest), which was completed in mid-December 2014 and slowly ramped up to about 600 BOPD, has continued to flow 600 BOPD on an 11/64ths-inch choke at a current flowing tubing pressure of approximately 1,060 psi.

◦

The Cane Creek Unit 28-2 well (100 percent working interest) was fracture stimulated in June 2015. Pre-stimulated production oil rate was 40 BOPD. After stimulation, the well had a peak oil production rate of 350 BOPD on a 6/64ths-inch choke and a flowing tubing pressure of 3,600 psi. The well is currently flowing an average oil rate of 230 BOPD on a 10/64ths-inch choke and a flowing tubing pressure of 800 psi. These results are similar to those achieved from the successful fracture stimulation of the Cane Creek Unit 32-1 in 2014 and are very encouraging.


◦	Per-unit lease operating costs year-to-date 2015 were 18 percent lower than costs for the same period in 2014, after adjusting for 2014 asset divestments. Lower operating costs have been achieved through reductions in costs of services as well as optimizing production operations.

Annual oil production is expected to decline approximately 30 percent in 2015, primarily due to 2014 divestments in the Bakken and limited oil-related investments in 2015. Annual natural gas and NGL volumes are estimated to decrease 9 percent and 29 percent, respectively, in 2015, primarily the result of 2014 asset divestments in South Texas. The December 2015 oil production rate is estimated to decrease 28 percent compared to December 2014, while natural gas and NGL rates are estimated to decrease 6 percent and 9 percent, respectively. The Company is assuming average NYMEX index prices for August through December 2015 of $54.20 per Bbl of crude oil, $2.92 per Mcf of natural gas and $22.15 per Bbl of NGL.

Derivatives in place as of July 31, 2015, include:


◦	For July through September 2015, 6,000 BOPD at a weighted average price of $55.78.


◦	For October through December 2015, 6,000 BOPD at a weighted average price of $58.61.


◦	For July through December 2015, 10,000 MMBtu of natural gas per day at a weighted average price of $4.28.

NEW ACCOUNTING STANDARDS

For information regarding new accounting standards, see Note 9,7, which is incorporated by reference.

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

The Company's critical accounting policies involving significant estimates include impairment testing of oil and natural gas properties, 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 ~~2013~~2014 Annual ~~Report.~~Report other than the critical accounting policies involving impairment testing of oil and natural gas properties and the impairment testing of assets held for sale. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the ~~2013~~2014 Annual Report.

Oil and natural gas properties

Estimates of proved reserves are prepared in accordance with guidelines established by the industry and the SEC. The estimates are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. The extent, quality and reliability of this data can vary. Other factors used in the reserve estimates are prices, market differentials, estimates of well operating and future development costs, and timing of operations. These estimates are refined as new information becomes available.

As these estimates change, calculated proved reserves may change. Prior to the oil and natural gas properties being classified as held for sale, changes in proved reserve quantities impacted the Company's depreciation, depletion and amortization expense since the Company used the units-of-production method to amortize its oil and natural gas properties. Historically, the proved reserves were the underlying basis of the "ceiling test" for the Company's oil and natural gas properties while those properties were classified as held for use.

The Company uses the full-cost method of accounting for its exploration and production activities. Prior to the oil and natural gas properties being classified as held for sale, capitalized costs were subject to a "ceiling test" that limited such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows were determined based on SEC Defined Prices and excluded cash flows associated with asset retirement obligations that had been accrued on the balance sheet. Judgments and assumptions were made when estimating and valuing proved reserves.

In the second quarter of 2015, the Company announced its plan to market Fidelity and exit that line of business. The assets and liabilities were classified as held for sale and evaluated for impairment based on fair value less cost to sell, as discussed below under impairment testing of assets held for sale.

Impairment testing of assets held for sale

The Company evaluates disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. At the time the Company committed to the plan to sell Fidelity, the Company performed a fair value assessment of the assets classified as held for sale. The estimated fair value was determined using the income and the market approaches. The income approach was determined by using the present value of future estimated cash flows. The income approach considered management’s views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry including estimated reserves, estimated prices, market differentials, estimates of well operating and future

development costs and timing of operations. The estimated cash flows were discounted using a rate believed to be consistent with those used by principal market participants. The market approach was provided by a third party and based on market transactions involving similar interests in oil and natural gas properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the asset could be different using different estimates and assumptions in the valuation techniques used.

The Company believes its estimates used in calculating the fair value of its assets held for sale are reasonable based on the information that is known when the estimates are made.

LIQUIDITY AND CAPITAL COMMITMENTS

At ~~September~~June 30, ~~2014~~2015, the Company had cash and cash equivalents of $~~233.7~~144.4 million and available capacity of ~~$614.8~~$337.5 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year from various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.

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.

Cash flows provided by operating activities in the first ~~nine~~six months of ~~2014~~2015 decreased ~~$25.6~~$50.8 million from the comparable period in ~~2013~~2014. The decrease in cash flows provided by operating activities was primarily due to ~~higher working capital requirements~~lower earnings largely from lower commodity prices at the exploration and production business and lower earnings at the construction services and ~~construction materials~~pipeline and ~~contracting businesses partially offset by~~energy services businesses. Partially offsetting this decrease was lower working capital requirements at the electric, natural gas distribution ~~business.~~and construction services businesses.

Investing activities Cash flows used in investing activities in the first ~~nine~~six months of ~~2014~~2015 ~~increased $38.1~~decreased $183.3 million from the comparable period in ~~2013~~2014. The ~~increase~~decrease in cash flows used in investing activities was primarily due to ~~higher~~lower acquisition-related and ongoing capital expenditures ~~offset in part by~~at the exploration and production business and higher proceeds from the sale of ~~oil and natural gas properties, both~~property at the ~~exploration and production~~construction services business. Partially offsetting this decrease was higher ongoing capital expenditures at the electric business.

Financing activities Cash flows provided by financing activities in the first ~~nine~~six months of ~~2014~~2015 ~~increased $235.0~~decreased $123.3 million from the comparable period in ~~2013~~2014. The ~~increase~~decrease in cash flows provided by financing activities was primarily due to ~~higher~~lower issuance of long-term debt of ~~$175.0~~$120.5 million, as well as ~~the~~lower issuance ~~of $144.9 million~~ of common stock. Partially offsetting this ~~increase~~decrease was higher issuance of short-term borrowings and lower repayment of both short-term borrowings and long-term ~~debt of $63.0 million as well as higher dividends paid in 2014 compared to 2013 due to the acceleration of the first quarter 2013 quarterly common stock dividend to 2012.~~debt.

Defined benefit pension plans

There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the ~~2013~~2014 Annual Report. For more information, see Note 2015 and Part II, Item 7 in the ~~2013~~2014 Annual Report.

Capital expenditures

Capital expenditures for the first ~~nine~~six months of ~~2014~~2015 were ~~$819.2~~$356.0 million ($~~613.0~~323.1 million, net of proceeds from sale or disposition of property) ~~and are estimated to be approximately $1.1 billion for 2014~~, which includes $62.2 million ($~~838~~60.6 million, net of proceeds from sale or disposition of property). at the exploration and production business. Capital expenditures are estimated to be approximately $691 million for 2015 ($662 million, net of proceeds from sale or disposition of property), which includes $96 million ($100 million, net of proceeds/costs from sale or disposition of property) at the exploration and production business. 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

Further development of existing properties ~~and proceeds from the sale of certain assets~~ at the exploration and production ~~segment~~business

Power generation and transmission opportunities, including certain costs for additional electric generating capacity and purchase agreement of electric wind generation

Environmental upgrades

The Company's proportionate share of Dakota Prairie Refinery at the pipeline and energy services segment

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 ~~2014~~2015 capital expenditures referred to previously. The Company expects the ~~2014~~2015 estimated capital expenditures to be funded by various sources, including internally generated funds; the Company's credit facilities, as described later; ~~and~~ through the issuance of long-term debt and the Company's equity ~~securities.~~securities; 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 ~~September~~June 30, ~~2014~~2015. 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 ~~Note 17 and~~ Part II, Item 8 - Note 9, in the ~~2013~~2014 Annual Report.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at ~~September~~June 30, ~~2014~~2015:


Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
			(In millions)												(In millions)
MDU Resources Group, Inc.	Commercial paper/ Revolving credit agreement	(a)	$	175.0		$	—	(b)	$	—		5/8/19	Commercial paper/ Revolving credit agreement	(a)	$	175.0		$	135.3	(b)	$	—		5/8/19
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	14.0		$	2.2	(d)	7/9/18	Revolving credit agreement		$	50.0	(c)	$	—		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	15.5		$	—		7/13/18	Revolving credit agreement		$	65.0	(e)	$	15.9		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/ Revolving credit agreement	(f)	$	650.0		$	293.5	(b)	$	—		5/8/19	Commercial paper/ Revolving credit agreement	(f)	$	650.0		$	449.5	(b)	$	—		5/8/19
Dakota Prairie Refining, LLC													Revolving credit agreement		$	50.0	(g)	$	26.0		$	23.6	(d)	12/1/15

(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.

(d) An outstanding letter of credit reduces the amount available under the credit agreement.

(e) Certain provisions allow for increased borrowings, up to a maximum of $90.0 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 $800.0 million). There were no amounts outstanding under the credit agreement.

(g) Certain provisions allow for increased borrowing, up to a maximum of $75.0 million.

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. ~~On May 8, 2014, the Company amended the revolving credit agreement to increase the borrowing limit to $175.0 million and extend the termination date to May 8, 2019.~~ 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 fixed charges including preferred stock dividends was ~~4.9~~2.6 times, 3.5 times and ~~4.8~~3.1 times for the 12 months ended ~~September~~June 30, 2015 and 2014, and December 31, ~~2013~~2014. The Company's coverage of fixed charges including preferred stock dividends was 2.5 times for the 12 months ended September 30, 2013, including the after-tax noncash write-down of oil and natural gas properties of $145.9 million in the fourth quarter of 2012. If the $145.9 million after-tax noncash write-down was excluded, the coverage of fixed charges including preferred stock dividends would have been 4.7 times for the 12 months ended September 30, 2013., respectively.

The coverage of fixed charges including preferred stock dividends, that excludes the effect of the after-tax noncash write-down of oil and natural gas properties is a non-GAAP financial measure. The Company believes that this non-GAAP financial measure is useful because the write-down excluded is not indicative of the Company's cash flows available to meets its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for the financial measure prepared in accordance with GAAP.

Total equity as a percent of total capitalization was 5953 percent, 58 ~~percent~~ percent and 6061 percent at ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014, and December 31, ~~2013~~2014, 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 indicates how a company is financing its operations, as well as its financial strength.

On May 20, 2013, the Company entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 7.5 million shares of the Company's common stock. The common stock may be offered for sale, from time to time until February 28, 2016, in accordance with the terms and conditions of the agreement. ~~Sales of such common stock may not be made after February 28, 2016.~~ Proceeds from the shares of common stock under the agreement have been and are expected to be used for corporate development purposes and other general corporate purposes. Under the ~~Equity Distribution Agreement,~~agreement, the Company ~~issued 225,000 shares of stock between July 1, 2014 and September 30, 2014, receiving net proceeds of $7.7 million, 3.9 million~~did not issue any shares of stock between January 1, ~~2014~~2015 and ~~September~~June 30, ~~2014, receiving net proceeds~~2015. Since inception of ~~$130.1 million and~~the Equity Distribution Agreement, the Company has issued a cumulative total of 4.4 million shares of stock ~~as of September 30, 2014,~~ receiving net proceeds of $144.7 ~~million.~~million through June 30, 2015.

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

~~The~~On July 21, 2015, the Company entered into a ~~$150.0~~$75.0 million ~~note purchase~~term loan agreement ~~on January 28, 2014. On April 15, 2014, the Company issued $50.0 million of Senior Notes~~ with a ~~due date of April 15, 2044, at an~~variable interest rate ~~of 5.2 percent. The remaining $100.0 million of Senior Notes was issued~~which matures on July ~~15, 2014, with due dates ranging from July 15, 2024 to July 15, 2026, at a weighted average interest rate of 4.3 percent.~~

~~Centennial Energy Holdings, Inc.~~ ~~On May 8, 2014, Centennial entered into an amended and restated revolving credit agreement which increased the borrowing limit to $650.0 million and extended the termination date to May 8, 2019.~~20, 2016. The ~~credit~~ agreement contains customary covenants and provisions, including a covenant of ~~Centennial~~the Company not to permit, ~~as of the end of~~at any ~~fiscal quarter,~~time, the ratio of ~~total consolidated~~funded debt to ~~total~~capitalization (on either a consolidated ~~capitalization~~or unconsolidated basis) to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets ~~limitations on subsidiary indebtedness~~ and the making of certain ~~loans and~~ investments.

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.

Centennial entered into two separate two year $125.0 million term loan agreements with variable interest rates on March 31, 2014 and April 2, 2014, respectively. These agreements contain customary covenants and default provisions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of Centennial's total debt to total capitalization to be greater than 65 percent. The covenants also include certain limitations on subsidiary indebtedness and restrictions on the sale of certain assets and on the making of certain loans and investments. On August 6, 2014, Centennial paid all of the outstanding borrowings under one of the two year loan agreements and all the outstanding borrowings under the remaining two year term loan agreement were paid on October 2, 2014.

WBI Energy Transmission, Inc. WBI Energy Transmission has a $175.0 million amended and restated uncommitted long-term private shelf agreement with an expiration date of September 12, 2016. WBI Energy Transmission had $100.0 million of notes outstanding at ~~September~~June 30, ~~2014,~~2015, which reduced capacity under this uncommitted private shelf agreement.

Off balance sheet arrangements

In connection with the sale of the Brazilian Transmission Lines, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are 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. ~~For more information, see Note 13.~~

Contractual obligations and commercial commitments

There are no material changes in the Company's contractual obligations from continuing operations relating to estimated interest payments, operating leases, purchase commitments, ~~derivatives,~~ asset retirement obligations, uncertain tax positions and minimum funding requirements for its defined benefit plans for ~~2014~~2015 from those reported in the ~~2013~~2014 Annual Report.

The Company's contractual obligations relating to long-term debt at ~~September~~June 30, ~~2014~~,2015, increased ~~$356.0~~$283.0 million or 1914 percent from December 31, ~~2013.~~2014. As of ~~September~~June 30, ~~2014~~,2015, the Company's contractual obligations related to long-term debt aggregated ~~$2,210.6 million~~.$2,376.8 million. The scheduled amounts of redemption (for the twelve months ended ~~September~~June 30, of each year listed) aggregate ~~$149.1~~$418.5 million ~~in 2015;~~ ~~$488.2 million~~ in 2016; ~~$101.0~~$116.0 million in 2017; ~~$157.1~~$63.0 million in 2018; ~~$302.9~~$522.5 million in 2019; $249.7 million in 2020; and ~~$1,012.3~~$1,007.1 million thereafter.

For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the ~~2013~~2014 Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to the impact of market fluctuations associated with commodity prices and interest ~~rates and foreign currency.~~rates. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk.

For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the ~~2013~~2014 Annual Report, the Consolidated Statements of Comprehensive Income and Notes 108 and ~~15.~~11.

Commodity price risk

Fidelity utilizes derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on forecasted sales of oil and natural gas production. The derivative instruments held by Fidelity are classified as held for sale.

The following table summarizes derivative agreements entered into by Fidelity as of ~~September~~June 30, ~~2014~~2015. These agreements call for Fidelity to receive fixed prices and pay variable prices.


	(Forward notional volume and fair value in thousands)						(Forward notional volume and fair value in thousands)

		Weighted Average Fixed Price (Per Bbl/MMBtu)		Forward Notional Volume (Bbl/MMBtu)	Fair Value			Weighted Average Fixed Price (Per Bbl/MMBtu)		Forward Notional Volume (Bbl/MMBtu)	Fair Value
Oil swap agreements maturing in 2014		$	97.50	1,104	$	8,044
Oil swap agreements maturing in 2015		$	98.00	270	$	2,447		$	57.20	1,104	$	(3,511	)
Natural gas swap agreements maturing in 2014		$	4.10	3,680	$	16
Natural gas swap agreement maturing in 2015		$	4.28	3,650	$	1,030		$	4.28	1,840	$	2,537

Interest rate risk

There were no material changes to interest rate risk faced by the Company from those reported in the ~~2013~~2014 Annual Report.

At ~~September~~June 30, ~~2014~~2015, the Company had no outstanding interest rate hedges.

~~Foreign currency risk~~

The Company's investment in ECTE is exposed to market risks from changes in foreign currency exchange rates between the U.S. dollar and the Brazilian Real. For more information, see Part II, Item 8 - Note 4 in the ~~2013~~ ~~Annual Report.~~

At ~~September 30, 2014, the Company had no outstanding foreign currency 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 ~~September~~June 30, ~~2014~~2015, 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, see Note ~~22,~~17, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

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.

The Company is including the following factors and cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than 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 Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these factors and cautionary statements.

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.

There are no material changes in the Company's risk factors from those reported in Part I, Item 1A - Risk Factors in the ~~2013~~2014 Annual Report other than the risk that actual quantities of recoverable oil and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts; the ~~Company’s exploration and production business is subject to external influences;~~risk associated with the regulatory

approval, permitting, construction, startup and/or operation of power generation facilities; the risk associated with the operation of Dakota Prairie Refinery; the risk related to environmental laws and regulations; the risk that the Company's operations could be adversely impacted by initiatives to reduce GHG emissions; the risk related to obligations under ~~multiemployer pension plans;~~MEPPs; and ~~risks~~the risk related to the marketing and ~~potential sale of~~plans to sell the Company's exploration and production business. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

Economic Risks

The Company’s exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that are subject to various external influences that cannot be controlled.

~~These factors include: fluctuations in~~Actual quantities of recoverable oil, NGL and natural gas ~~production~~reserves and ~~prices; fluctuations~~discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in ~~commodity price basis differentials; availability~~estimates of ~~economic supplies of natural gas; drilling successes in~~proved reserve quantities or other factors including low oil and natural gas ~~operations;~~prices, could result in future noncash impairments of the ~~timely receipt~~Company's exploration and production business.

The process of necessary permits and approvals; the ability to contract for or to secure necessary drilling rig and service contracts and to retain employees to identify, drill for and develop reserves; utilizing appropriate technologies; irregularities in geological formations; and other risks incidental to the development and operations of oil and natural gas wells, processing plants and pipeline systems. Volatility inestimating oil, NGL and natural gas reserves is complex. Reserve estimates are based on assumptions relating to oil, NGL and natural gas pricing, drilling and operating expenses, capital expenditures and timing of operations. The proved reserve estimates are prepared for each of the Company's properties by internal engineers assigned to an asset team by geographic area. The internal engineers analyze available geological, geophysical, engineering and economic data for each geographic area. The internal engineers make various assumptions regarding this data. The extent, quality and reliability of this data can vary. Although the Company has prepared its proved reserve estimates in accordance with guidelines established by the industry and the SEC, significant changes to the proved reserve estimates may occur based on actual results of production, drilling, costs, pricing and investment levels.

The Company bases the estimated discounted future net cash flows from proved reserves on prices and current costs in accordance with GAAP. Actual future prices and costs may be significantly different. Various factors, including lower oil and natural gas prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in future noncash impairments of the Company's exploration and production business.

The regulatory approval, permitting, construction, startup and/or operation of power generation facilities may involve unanticipated events or delays that could negatively ~~affect~~impact the Company's business and its results of operations and cash flows.

The construction, startup and operation of power generation facilities involve many risks, which may include: delays; breakdown or failure of equipment; inability to obtain required governmental permits and approvals; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel supply, off-take, transmission, transportation or other material agreements; changes in markets and market prices for power; cost increases and overruns; the risk of performance below expected levels of output or efficiency; and the inability to obtain full cost recovery in regulated rates. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.

The operation of Dakota Prairie Refinery may involve unanticipated events that could negatively impact the Company's business and its results of operations and cash flows.

The operation of Dakota Prairie Refinery involves many risks, which may include: breakdown or failure of the equipment and systems; inability to operate within environmental permit parameters; inability to produce refined products to required specifications; inability to obtain crude oil supply; inability to effectively manage new rail routes; changes in markets and market prices for crude oil and refined products; operating cost increases; and the inability of Dakota Prairie Refinery to fund its operations from its operating cash flows, by obtaining third-party financing or through capital contributions from Calumet or WBI Energy; as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company's business, its results of operations and ~~asset values of the Company’s exploration and production and pipeline and energy services businesses.~~cash flows.

Environmental and Regulatory Risks

The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

The Company is subject to environmental laws and regulations affecting many aspects of its operations, including air quality, water quality, waste management and other environmental considerations. These laws and regulations can increase capital, operating and other costs, cause delays as a result of litigation and administrative proceedings, and create compliance, remediation, containment, monitoring and reporting obligations, particularly relating to electric generation operations and oil and natural gas development and processing. These laws and regulations generally require the Company to obtain and comply

with a wide variety of environmental licenses, permits, inspections and other approvals. Although the Company strives to

comply with all applicable environmental laws and regulations, public and private entities and private individuals may interpret the Company's legal or regulatory requirements differently and seek injunctive relief or other remedies against the Company. The Company cannot predict the outcome (financial or operational) of any such litigation or administrative proceedings.

Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain facilities, restrict the use of certain fuels, install pollution controls, remediate environmental contamination, remove or reduce environmental hazards, or prevent or limit the development of resources. Revised or additional laws and regulations that increase compliance costs or restrict operations, particularly if costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.

~~The~~In 2010, the EPA issued draft regulations that ~~outline~~outlined several possible approaches for coal combustion residuals management under the RCRA. ~~One approach, designating~~On April 17, 2015, the EPA published a final rule for coal combustion residuals that regulates coal ash as a solid waste and not a hazardous ~~waste, if adopted would significantly change~~waste. The rule requires ground water and location restriction evaluations be conducted at ash impoundments and landfills not located at coal mines by October 2017. Depending on the ~~manner~~evaluation results, the Company’s ash impoundments may need to be upgraded or closed, and ~~increase~~ the Company may need to install replacement ash management systems in the future. The cost of replacement ash impoundments or landfills may be material. If these costs are not fully recoverable from customers, they could have a material adverse effect on the Company's results of managing coal ash at five plants that supply electricity to customers of Montana-Dakota. This designation also could significantly increase costs for Knife River, which beneficially uses fly ash as a cement replacement in ready-mixed concreteoperations and ~~road base applications.~~cash flows.

In December 2011, the EPA finalized the ~~Mercury and Air Toxics Standards rules that will require~~MATS rule requiring reductions in mercury and other air emissions from coal- and oil-fired electric utility steam generating units. Montana-Dakota evaluated the pollution control technologies needed at its electric generation resources to comply with this rule and determined ~~that~~ the Lewis & Clark Station near Sidney, Montana, will require additional particulate matter control for non-mercury metal emissions. Montana-Dakota ~~intends~~further evaluated pollution control options and is making scrubber modifications, including installing a mist eliminator and sieve tray at the Lewis & Clark Station, to comply with the rule. On June 29, 2015, the United States Supreme Court reversed a prior decision of the D.C. Circuit Court upholding the validity of the MATS rule. The United States Supreme Court remanded the case to the D.C. Circuit Court for further proceedings; however, the D.C. Circuit Court has not yet acted regarding further proceedings. The MATS rule ~~by co-firing~~was not vacated or stayed; therefore, pollution controls at the ~~plant with natural gas~~Lewis & Clark Station must still be installed and ~~lignite; however, scrubber modifications may also be needed for compliance. Controls must be~~ in ~~place~~operation by April 16, ~~2015, or April 16,~~ 2016, iffor Montana-Dakota to comply with the rule.

On August 15, 2014, the EPA published a ~~one-year extension is granted for completion~~final rule under Section 316(b) of the ~~pollution control project.~~Clean Water Act, establishing requirements for water intake structures at existing steam electric generating facilities. The purpose of the rule is to reduce impingement and entrainment of fish and other aquatic organisms at cooling water intake structures. The majority of the Company's electric generating facilities are either not subject to the rule or have completed studies that project compliance expenditures are not material. The Lewis & Clark Station will complete a study that will be submitted to the Montana DEQ by July 31, 2019, to be used in determining any required controls. It is unknown at this time what controls may be required or if compliance costs will be material. The installation schedule for any required controls would be established with the permitting agency after the study is completed.

~~Hydraulic~~Fidelity uses hydraulic fracturing, is an important common practice ~~used by Fidelity~~ that involves injecting water, sand, a water-thickening agent called guar, and trace amounts of chemicals, under pressure, into rock formations to stimulate oil, NGL and natural gas production. Fidelity follows state regulations for well drilling and completion, including regulations ~~for~~on hydraulic fracturing and ~~recovered fluids~~recovered-fluids disposal. ~~Fracturing~~Fidelity reports fracturing fluid constituents ~~are reported~~ on state or national websites. The EPA is developing a study to review potential effects of hydraulic fracturing on underground sources of drinking water; the results of that study could impact future legislation or regulation. The BLM ~~has released draft well stimulation~~issued well-stimulation regulations for hydraulic fracturing ~~operations. If implemented, the BLM regulations would affect~~operations, effective June 24, 2015, that impact Fidelity’s compliance, reporting and disclosures on operations only ~~Fidelity's operations~~ on BLM-administered lands. ~~If adopted as proposed, the BLM~~The BLM’s regulations along with other legislative initiatives and regulatory studies, proceedings or initiatives at federal or state agencies that focus on the hydraulic fracturing process, could result in additional compliance, reporting and disclosure requirements. Future legislation or regulation could increase Fidelity’s compliance and operating costs, as well as delay or inhibit the ~~Company's~~Company’s ability to develop its oil, NGL and natural gas reserves.

On August 16, 2012, the EPA published a final NSPS rule for the oil and natural gas ~~industry. The NSPS rule phases~~industry that took effect in ~~over two years.~~phases. The first phase was effective October 15, 2012, and primarily covers natural gas wells that are hydraulically fractured. Under the ~~new~~ rule, gas vapors or emissions from the natural gas wells must be captured or combusted utilizing a high-efficiency device. ~~Additional~~Effective January 2015, additional reporting requirements and control devices covering oil and natural gas production equipment ~~will be~~were phased in for certain new oil and gas ~~facilities with a final effective date of January 1, 2015.~~facilities. This ~~new~~ rule's impacts on Fidelity, WBI Energy Transmission and WBI Energy Midstream are not expected to be material and ~~are likely to include~~have included implementing recordkeeping, reporting and testing requirements and purchasing and installing required equipment.

Initiatives to reduce GHG emissions could adversely impact the Company's operations.

Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. On June 25, 2013, President Obama released his Climate Action Plan for the ~~U.S.~~United States in which he stated his goal to reduce GHG emissions "in the range of 17 percent" below 2005 levels by 2020. The president issued a memorandum to the EPA on the same day, instructing the EPA to re-propose the GHG NSPS rule for new electric generation units. The EPA released the re-proposed rule on January 8, 2014, in the Federal Register, which takes the place of the rule proposed in 2012 for new electric ~~generation~~generating units that the EPA did not finalize. This rule applies to new fossil fuel-fired electric ~~generation~~generating units, including coal-fired units, natural gas-fired combined-cycle units and natural gas-fired simple-cycle peaking units. The EPA's 1,100 pounds of carbon dioxide per MW hour emissions standard for coal-fired units does not allow any new coal-fired electric generation to be constructed unless carbon dioxide is captured and sequestered.

President Obama also directed the EPA to develop a GHG NSPS standard for existing fossil fuel-fired electric generation units by June 1, 2014, with finalization by June 1, 2015. On June 18, 2014, the EPA published in the Federal Register a proposed rule limiting carbon dioxide emissions from existing fossil fuel-fired electric generating units and a separate proposed rule limiting carbon dioxide emissions from existing units that are modified or reconstructed.

In the proposed rule for existing sources, the EPA requires carbon dioxide emission reductions from each state and instructs each state, or group of states that work together, to submit a plan ~~to the EPA~~ by June 30, 2016, to the EPA that demonstrates how the state will achieve the targeted emission reductions by 2030. The state plans could include performance standards, emissions reductions or limits on generation for each existing fossil fuel-fired generating unit. It is unknown at this time what each state will require for emissions reductions from each ~~Montana-Dakota~~of Montana-Dakota's owned and jointly owned fossil fuel-fired electric generating ~~unit.~~units. In the EPA’s proposed GHG rule for modified or reconstructed fossil fuel-fired sources, the EPA proposes emissions limits that potentially could ~~potentially~~ be unachievable. Montana-Dakota does not plan to modify or reconstruct any fossil fuel-fired units at this time, but it may modify or reconstruct units in the future ~~which must comply~~that may require compliance with the rule limitations.

The Company’s primary GHG emission is carbon dioxide from fossil fuels combustion at Montana-Dakota's electric generating facilities, particularly its coal-fired facilities. Approximately 7060 percent of Montana-Dakota's owned generating capacity and more than 90 percent of the electricity it generates is from coal-fired facilities.

On January 14, 2015, President Obama announced a goal to reduce methane emissions from the oil and natural gas industry by 40 to 45 percent below 2012 levels by 2025. The EPA will issue in mid-2015 a proposed rule on standards for methane and GHG emissions from new and modified sources within the oil and natural gas industry, with a final rule expected in 2016. The rule is expected to include emission reductions on sources such as oil well completions, pneumatic pumps, and leaks from well sites, gathering and boosting stations, and compressor stations. The president will continue to evaluate further methods of methane reduction including additional leak detection controls and emission reporting, enhanced venting and flaring requirements for sources on public lands, and upgrades to existing natural gas transmission and distribution infrastructure. It is unknown at this time how the Company will be impacted or if compliance costs will be material.

There also may ~~also~~ be new treaties, legislation or regulations to reduce GHG emissions that could affect Montana-Dakota's electric utility operations by requiring additional energy conservation efforts or renewable energy sources, as well as other mandates that could significantly increase capital expenditures and operating costs. If Montana-Dakota does not receive timely and full recovery of GHG emission compliance costs from its customers, then such costs could adversely impact the results of its operations.

In addition to Montana-Dakota's electric generation operations, the GHG emissions from the Company's other operations are monitored, analyzed and reported as required by applicable laws and regulations. The Company monitors GHG regulations and the potential for GHG regulations to impact operations.

Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the potential financial impact on its operations.

Other Risks

An increase in costs related to obligations under ~~multiemployer pension plans~~MEPPs could have a material negative effect on the Company's results of operations and cash flows.

Various operating subsidiaries of the Company participate in approximately ~~80 multiemployer pension plans~~85 MEPPs for employees represented by certain unions. The Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements between the operating subsidiaries and those unions.

The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously endangered or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are required to adopt RPs or FIPs to improve their funded status through increased contributions, reduced benefits or a combination of the two. Based on available information, the Company believes that approximately 40 percent of the ~~multiemployer plans~~MEPPs to which it contributes are currently in endangered, seriously endangered or critical status.

The Company may also be required to increase its contributions to ~~multiemployer plans~~MEPPs where the other participating employers in such plans withdraw from the plan and are not able to contribute an amount sufficient to fund the unfunded liabilities associated with their participants in the plans. The amount and timing of any increase in the Company's required contributions to ~~multiemployer pension plans~~MEPPs may also depend upon one or more of the following factors including the outcome of collective bargaining, actions taken by trustees who manage the plans, actions taken by the plans' other participating employers, the industry for which contributions are made, future determinations that additional plans reach endangered, seriously endangered or critical status, government regulations and the actual return on assets held in the plans, among others. The Company may experience increased operating expenses as a result of the required contributions to ~~multiemployer pension plans,~~MEPPs, which may have a material adverse effect on the Company's results of operations, financial position or cash flows.

In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan to the extent these plans are underfunded.

On September 24, 2014, Knife River provided notice to the plan administrator ~~under~~of one of the ~~multiemployer pension plans~~MEPPs to which ~~Knife River~~it is a ~~party~~participating employer that it was withdrawing from ~~the~~that plan effective October 26, 2014. The plan administrator will determine Knife River’s withdrawal liability, which the Company currently estimates at approximately ~~$14~~$16.4 million (approximately ~~$8.4~~$9.8 million after tax). ~~Actual~~The assessed withdrawal liability ~~costs~~for this plan may be significantly ~~different.~~different from the current estimate.

While the Company is marketing and plans to ~~market and potentially~~ sell Fidelity, its exploration and production business, there is no assurance that it will be successful.

As part of the Company’s corporate strategy, it is marketing and plans to ~~market and potentially~~ sell its ~~exploration and production~~Fidelity assets and exit that line of business. Such a disposition and exit iswill be subject to various risks, including: suitable purchasers may not be available or willing to purchase the assets on terms and conditions acceptable to the Company or may only be interested in acquiring a portion of the assets; the agreements pursuant to which the Company divests the assets may contain continuing indemnification obligations; the inability to obtain waivers from applicable covenants under debt agreements; the Company may incur substantial costs in connection with the marketing and sale of the assets; the marketing and sale of the assets could distract management, divert resources, disrupt the Company’s ongoing business and make it difficult for the Company to maintain its current business standards, controls and procedures; uncertainties associated with the sale may cause a loss of key management personnel at Fidelity which could make it more difficult to sell the assets or operate the business in the event that the Company is unable to sell it; ~~sale~~there could be various tax consequences dependent on the nature of the ~~assets could result in substantial tax liability; if~~sale; the Company ~~is unable to sell the assets it~~ may be required to record an ~~impaired asset~~additional impairment charge that could have an adverse effect on the Company’s financial condition; and the Company may not be able to redeploy the proceeds from any sale of the assets in a manner that produces similar revenues and growth rates or enhances shareholder value.

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 6. EXHIBITS

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

5457

SIGNATURES

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



		MDU RESOURCES GROUP, INC.

DATE:	~~November 7, 2014~~August 4, 2015	BY:	/s/ Doran N. Schwartz
			Doran N. Schwartz
			Vice President and Chief Financial Officer


		BY:	/s/ Nathan W. Ring
			Nathan W. Ring
			Vice President, Controller and Chief Accounting Officer

5558

EXHIBIT INDEX



Exhibit No.

+10(a)		~~Purchase and Sale Agreement, dated July 17, 2014, between Fidelity Exploration & Production Company and Lime Rock Resources, III-A, L.P.~~

~~+10(b)~~		Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated ~~September~~June 30, ~~2014~~2015

+10(b)		Waiver and Voluntary Release, dated July 17, 2015, between Steven L. Bietz and WBI Holdings, Inc.

+10(c)		MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of July 21, 2015

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 ~~September~~June 30, ~~2014,~~2015, 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

+ 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.

5659



Commodity	Type	Index	Period Outstanding	Forward Notional Volume (Bbl/MMBtu)	Price (Per Bbl/MMBtu)
Crude Oil	Swap	NYMEX	10/14 - 12/14	92,000	$94.05
Crude Oil	Swap	NYMEX	10/14 - 12/14	92,000	$94.25
Crude Oil	Swap	NYMEX	10/14 - 12/14	184,000	$95.00
Crude Oil	Swap	NYMEX	10/14 - 12/14	92,000	$95.25
Crude Oil	Swap	NYMEX	10/14 - 12/14	184,000	$96.00
Crude Oil	Swap	NYMEX	10/14 - 12/14	276,000	$100.50
Crude Oil	Swap	NYMEX	10/14 - 12/14	184,000	$101.50
Crude Oil	Swap	NYMEX	1/15 - 3/15	270,000	$98.00
Natural Gas	Swap	NYMEX	10/14 - 12/14	1,840,000	$4.13
Natural Gas	Swap	NYMEX	10/14 - 12/14	920,000	$4.05
Natural Gas	Swap	NYMEX	10/14 - 12/14	920,000	$4.10
Natural Gas	Swap	NYMEX	1/15 - 12/15	3,650,000	$4.28

(In thousands)

Property, plant and equipment additions in accounts payable