Edgar Filing: MDU RESOURCES GROUP INC

(In thousands)

Property, plant and equipment additions in accounts payable

WebFilings | MDU-6.30.2012-10Q 2

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For The Quarterly Period Ended June 30, 2012



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 July 31, 2012: 188,830,529 shares.

DEFINITIONS

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



Abbreviation or Acronym
2011 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2011
Alusa	Tecnica de Engenharia Electrica - Alusa
ASC	FASB Accounting Standards Codification
BART	Best available retrofit technology
Bbl	Barrel
Bicent	Bicent Power LLC
Big Stone Station	450-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
Brazilian Transmission Lines	Company's equity method investment in the company 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 fourth quarters of 2011 and 2010)
Btu	British thermal unit
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CELESC	Centrais Elétricas de Santa Catarina S.A.
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
CEMIG	Companhia Energética de Minas Gerais
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 Air Act	Federal Clean Air Act
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
ECTE	Empresa Catarinense de Transmissão de Energia S.A. (7.51 percent ownership interest at June 30, 2012, 2.5 and 14.99 percent ownership interests were sold in 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. 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
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
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
IFRS	International Financial Reporting Standards
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
LPP	Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)



LWG	Lower Willamette Group
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
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million decatherms
MNDOC	Minnesota Department of Commerce
MNPUC	Minnesota Public Utilities Commission
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
NDPSC	North Dakota Public Service Commission
New York Supreme Court	Supreme Court of the State of New York, County of New York
NSPS	New Source Performance Standards
Oil	Includes crude oil, condensate and natural gas liquids
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
RCRA	Resource Conservation and Recovery Act
ROD	Record of Decision
RP	Rehabilitation plan
SEC	U.S. 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
WBI Energy Midstream	WBI Energy Midstream, LLC an indirect wholly owned subsidiary of WBI Holdings (previously Bitter Creek Pipelines, LLC, name changed effective July 1, 2012)
WBI Energy Transmission	WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings (previously Williston Basin Interstate Pipeline Company, name changed effective July 1, 2012)
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC	Washington Utilities and Transportation 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 and the exploration and production segments), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category). For more information on the Company's business segments, see Note 14.

INDEX



Part I -- Financial Information	Page

Consolidated Statements of Income -- Three and Six Months Ended June 30, 2012 and 2011	6

Consolidated Statements of Comprehensive Income -- Three and Six Months Ended June 30, 2012 and 2011	7

Consolidated Balance Sheets -- June 30, 2012 and 2011, and December 31, 2011	8

Consolidated Statements of Cash Flows -- Six Months Ended June 30, 2012 and 2011	9

Notes to Consolidated Financial Statements	10

Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Quantitative and Qualitative Disclosures About Market Risk	42

Controls and Procedures	43

Part II -- Other Information

Legal Proceedings	44

Risk Factors	44

Unregistered Sales of Equity Securities and Use of Proceeds	47

Mine Safety Disclosures	47

Exhibits	47

Signatures	48

Exhibit Index	49

Exhibits

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012		2011			2012		2011
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	204,455	$	274,538		$	599,533	$	752,018
Exploration and production, construction materials and contracting, construction services and other	763,507		656,219			1,221,236		1,080,544
Total operating revenues	967,962		930,757			1,820,769		1,832,562
Operating expenses:
Fuel and purchased power	15,193		14,474			33,613		31,428
Purchased natural gas sold	58,411		101,538			243,839		346,224
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	52,717		70,028			121,115		137,989
Exploration and production, construction materials and contracting, construction services and other	623,347		536,608			999,497		896,408
Depreciation, depletion and amortization	83,627		83,290			169,007		167,964
Taxes, other than income	42,953		42,516			90,928		92,181
Total operating expenses	876,248		848,454			1,657,999		1,672,194
Operating income	91,714		82,303			162,770		160,368
Earnings from equity method investments	385		949			1,637		1,433
Other income	1,249		1,908			2,349		3,809
Interest expense	17,650		20,036			37,089		42,053
Income before income taxes	75,698		65,124			129,667		123,557
Income taxes	26,691		19,889			44,769		35,793
Income from continuing operations	49,007		45,235			84,898		87,764
Income (loss) from discontinued operations, net of tax (Note 8)	5,106		(168		)	5,006		280
Net income	54,113		45,067			89,904		88,044
Dividends declared on preferred stocks	171		171			343		342
Earnings on common stock	$	53,942	$	44,896		$	89,561	$	87,702

Earnings per common share - basic:
Earnings before discontinued operations	$	.26	$	.24		$	.45	$	.46
Discontinued operations, net of tax	.03		—			.02		—
Earnings per common share - basic	$	.29	$	.24		$	.47	$	.46

Earnings per common share - diluted:
Earnings before discontinued operations	$	.26	$	.24		$	.45	$	.46
Discontinued operations, net of tax	.03		—			.02		—
Earnings per common share - diluted	$	.29	$	.24		$	.47	$	.46

Dividends declared per common share	$	.1675	$	.1625		$	.3350	$	.3250

Weighted average common shares outstanding - basic	188,831		188,794			188,821		188,732

Weighted average common shares outstanding - diluted	189,107		188,968			189,096		188,903

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(In thousands)
Net income	$	54,113		$	45,067		$	89,904		$	88,044
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $15,059 and $10,576 for the three months ended and $13,129 and $(388) for the six months ended in 2012 and 2011, respectively	25,773			17,057			22,506			(1,217		)
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $1,077 and $(2,191) for the three months ended and $2,738 and $91 for the six months ended in 2012 and 2011, respectively	1,834			(3,650		)	4,666			155
Net unrealized gain (loss) on derivative instruments qualifying as hedges	23,939			20,707			17,840			(1,372		)
Foreign currency translation adjustment, net of tax of $(402) and $32 for the three months ended and $(265) and $170 for the six months ended in 2012 and 2011, respectively	(579		)	50			(435		)	262
Net unrealized gain (loss) on available-for-sale investments, net of tax of $(3) and $47 for the three months ended and $11 and $55 for the six months ended in 2012 and 2011, respectively	(5		)	87			21			103
Other comprehensive income (loss)	23,355			20,844			17,426			(1,007		)
Comprehensive income	$	77,468		$	65,911		$	107,330		$	87,037

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

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2012			June 30, 2011			December 31, 2011
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	101,643		$	107,768		$	162,772
Receivables, net	654,609			566,366			646,251
Inventories	333,392			277,327			274,205
Deferred income taxes	21,451			33,732			40,407
Commodity derivative instruments	37,000			14,234			27,687
Prepayments and other current assets	85,729			71,604			43,316
Total current assets	1,233,824			1,071,031			1,194,638
Investments	99,343			116,368			109,424
Property, plant and equipment	8,068,177			7,394,616			7,646,222
Less accumulated depreciation, depletion and amortization	3,478,118			3,236,417			3,361,208
Net property, plant and equipment	4,590,059			4,158,199			4,285,014
Deferred charges and other assets:
Goodwill	635,389			634,931			634,931
Other intangible assets, net	18,656			23,337			20,843
Other	324,299			253,515			311,275
Total deferred charges and other assets	978,344			911,783			967,049
Total assets	$	6,901,570		$	6,257,381		$	6,556,125

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Long-term debt due within one year	$	282,199		$	62,571		$	139,267
Accounts payable	379,840			304,049			337,228
Taxes payable	46,919			45,065			70,176
Dividends payable	31,800			30,850			31,794
Accrued compensation	37,774			37,978			47,804
Commodity derivative instruments	1,037			18,686			13,164
Other accrued liabilities	244,922			224,220			259,320
Total current liabilities	1,024,491			723,419			898,753
Long-term debt	1,383,432			1,369,534			1,285,411
Deferred credits and other liabilities:
Deferred income taxes	839,683			727,562			769,166
Other liabilities	833,692			711,516			827,228
Total deferred credits and other liabilities	1,673,375			1,439,078			1,596,394
Commitments and contingencies
Stockholders' equity:
Preferred stocks	15,000			15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 189,369,450 at June 30, 2012, 189,332,485 at June 30, 2011 and 189,332,485 at December 31, 2011	189,369			189,332			189,332
Other paid-in capital	1,036,935			1,033,366			1,035,739
Retained earnings	1,612,169			1,523,546			1,586,123
Accumulated other comprehensive loss	(29,575		)	(32,268		)	(47,001		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,805,272			2,710,350			2,760,567
Total stockholders' equity	2,820,272			2,725,350			2,775,567
Total liabilities and stockholders' equity	$	6,901,570		$	6,257,381		$	6,556,125

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,
	2012			2011
	(In thousands)
Operating activities:
Net income	$	89,904		$	88,044
Income from discontinued operations, net of tax	5,006			280
Income from continuing operations	84,898			87,764
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	169,007			167,964
Earnings, net of distributions, from equity method investments	1,251			512
Deferred income taxes	76,987			60,960
Changes in current assets and liabilities, net of acquisitions:
Receivables	(2,470		)	17,259
Inventories	(58,367		)	(29,154		)
Other current assets	(33,556		)	(19,600		)
Accounts payable	(7,119		)	(3,197		)
Other current liabilities	(45,562		)	(9,753		)
Other noncurrent changes	(10,070		)	(17,969		)
Net cash provided by continuing operations	174,999			254,786
Net cash used in discontinued operations	(258		)	(491		)
Net cash provided by operating activities	174,741			254,295

Investing activities:
Capital expenditures	(388,449		)	(224,934		)
Acquisitions, net of cash acquired	(65,767		)	(157		)
Net proceeds from sale or disposition of property and other	29,454			16,145
Investments	11,172			(9,955		)
Net cash used in continuing operations	(413,590		)	(218,901		)
Net cash provided by discontinued operations	—			—
Net cash used in investing activities	(413,590		)	(218,901		)

Financing activities:
Repayment of short-term borrowings	—			(20,000		)
Issuance of long-term debt	299,945			6,000
Repayment of long-term debt	(58,605		)	(81,202		)
Proceeds from issuance of common stock	88			5,744
Dividends paid	(63,594		)	(61,623		)
Excess tax benefit on stock-based compensation	26			1,248
Net cash provided by (used in) continuing operations	177,860			(149,833		)
Net cash provided by discontinued operations	—			—
Net cash provided by (used in) financing activities	177,860			(149,833		)
Effect of exchange rate changes on cash and cash equivalents	(140		)	133
Decrease in cash and cash equivalents	(61,129		)	(114,306		)
Cash and cash equivalents -- beginning of year	162,772			222,074
Cash and cash equivalents -- end of period	$	101,643		$	107,768

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

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

June 30, 2012 and 2011

(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 2011 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 2011 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after June 30, 2012, up to the date of issuance of these consolidated interim financial statements.

Note 2 - Seasonality of operations

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

Note 3 - Accounts receivable and allowance for doubtful accounts

Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $35.3 million, $41.4 million and $29.8 million as of June 30, 2012 and 2011, and December 31, 2011.

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 as of June 30, 2012 and 2011, and December 31, 2011, was $12.4 million, $14.2 million and $12.4 million, respectively.

Note 4 - Inventories and natural gas in storage

Inventories, other than natural gas in storage for the Company's regulated operations, were 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. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories consisted of:



	June 30, 2012		June 30, 2011		December 31, 2011
	(In thousands)
Aggregates held for resale	$	90,992	$	82,936	$	78,518
Asphalt oil	81,915		55,729		32,335
Materials and supplies	72,321		65,363		61,611
Merchandise for resale	30,417		33,435		32,165
Natural gas in storage (current)	26,216		11,993		36,578
Other	31,531		27,871		32,998
Total	$	333,392	$	277,327	$	274,205

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $50.3 million, $47.2 million, and $50.3 million at June 30, 2012 and 2011, and December 31, 2011, respectively.

Note 5 - Earnings per common share

Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per common share were computed by

dividing earnings 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 stock options and performance share awards. Common stock outstanding includes issued shares less shares held in treasury. Net income was the same for both the basic and diluted earnings per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings per share calculation was as follows:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
	(In thousands)
Weighted average common shares outstanding - basic	188,831	188,794	188,821	188,732
Effect of dilutive stock options and performance share awards	276	174	275	171
Weighted average common shares outstanding - diluted	189,107	188,968	189,096	188,903
Shares excluded from the calculation of diluted earnings per share	—	—	—	—

Note 6 - Cash flow information

Cash expenditures for interest and income taxes were as follows:



	Six Months Ended
	June 30,
	2012		2011
	(In thousands)
Interest, net of amount capitalized	$	35,893	$	40,646
Income taxes, net	$	2,418	$	12,887

Noncash investing transactions were as follows:

Note 7 - New accounting standards

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements. The guidance generally clarifies the application of existing requirements on topics including the concepts of highest and best use and valuation premise and disclosing quantitative information about the unobservable inputs used in the measurement of instruments categorized within Level 3 of the fair value hierarchy. Additionally, the guidance includes changes on topics such as measuring fair value of financial instruments that are managed within a portfolio and additional disclosure for fair value measurements categorized within Level 3 of the fair value hierarchy. This guidance was effective for the Company on January 1, 2012. The guidance requires additional disclosures, but it did not impact the Company's results of operations, financial position or cash flows.

Presentation of Comprehensive Income In June 2011, the FASB issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of stockholders' equity. The guidance allows the Company the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB indefinitely deferred the effective date for the guidance related to the presentation of reclassifications of items out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. This guidance, except for the portion that was indefinitely deferred, was effective for the Company on January 1, 2012, and must be applied retrospectively. The guidance requires the Company to present a consolidated statement of comprehensive income as part of its basic financial statements along with other revisions to the disclosures, but it did not impact the Company's results of operations, financial position or cash flows.

Note 8 - Discontinued operations

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 incurs legal expenses and has accrued liabilities related to this matter. In the second quarter of 2012,

discontinued operations reflects a net benefit largely related to estimated insurance recoveries related to this matter. In the first quarter of 2011, the Company had an income tax benefit related to favorable resolution of certain tax matters. These items are reflected as discontinued operations in the consolidated financial statements and accompanying notes. Discontinued operations are included in the Other category. For more information, see Note 18.

Note 9 - 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. The Company's equity method investments at June 30, 2012, include ECTE.

In August 2006, MDU Brasil acquired ownership interests in the Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.

In 2009, multiple sales agreements were signed for the Company to sell its ownership interest 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 remaining interest in ECTE is being purchased over a four-year period. In November 2011, the Company completed the sale of one-fourth of the remaining interest. Alusa, CEMIG and CELESC hold the remaining ownership interests in ECTE.

At June 30, 2012 and 2011, and December 31, 2011, the Company's equity method investments had total assets of $104.4 million, $107.7 million and $111.1 million, respectively, and long-term debt of $30.3 million, $49.6 million and $37.1 million, respectively. The Company's investment in its equity method investments was approximately $7.4 million, $11.4 million and $9.2 million, including undistributed earnings of $2.3 million, $2.1 million and $3.7 million, at June 30, 2012 and 2011, and December 31, 2011, respectively.

Note 10 - Goodwill and other intangible assets

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



Six Months Ended June 30, 2012	Balance as of January 1, 2012*		Goodwill Acquired During the Year**		Balance as of June 30, 2012*
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736
Pipeline and energy services	9,737		—		9,737
Construction materials and contracting	176,290		—		176,290
Construction services	103,168		458		103,626
Total	$	634,931	$	458	$	635,389

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

** Includes a purchase price adjustment that was not material related to an acquisition in a prior period.



Six Months Ended June 30, 2011	Balance as of January 1, 2011*		Goodwill Acquired During the Year**		Balance as of June 30, 2011*
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736
Pipeline and energy services	9,737		—		9,737
Construction materials and contracting	176,290		—		176,290
Construction services	102,870		298		103,168
Total	$	634,633	$	298	$	634,931

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

** Includes a purchase price adjustment that was not material related to an acquisition in a prior period.



Year Ended December 31, 2011	Balance as of January 1, 2011*		Goodwill Acquired During the Year**		Balance as of December 31, 2011*
	(In thousands)
Natural gas distribution	$	345,736	$	—	$	345,736
Pipeline and energy services	9,737		—		9,737
Construction materials and contracting	176,290		—		176,290
Construction services	102,870		298		103,168
Total	$	634,633	$	298	$	634,931

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

** Includes a purchase price adjustment that was not material related to an acquisition in a prior period.

Other amortizable intangible assets were as follows:



	June 30, 2012			June 30, 2011			December 31, 2011
	(In thousands)
Customer relationships	$	21,010		$	21,702		$	21,702
Accumulated amortization	(10,690		)	(9,395		)	(10,392		)
	10,320			12,307			11,310
Noncompete agreements	7,086			7,685			7,685
Accumulated amortization	(5,057		)	(5,062		)	(5,371		)
	2,029			2,623			2,314
Other	10,978			12,899			11,442
Accumulated amortization	(4,671		)	(4,492		)	(4,223		)
	6,307			8,407			7,219
Total	$	18,656		$	23,337		$	20,843

Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2012, was $1.0 million and $1.9 million, respectively. Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2011, was $1.0 million and $1.9 million, respectively. Estimated amortization expense for amortizable intangible assets is $3.8 million in 2012, $3.6 million in 2013, $3.3 million in 2014, $2.6 million in 2015, $2.1 million in 2016 and $5.2 million thereafter.

Note 11 - 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 June 30, 2012, the Company had no outstanding foreign currency hedges. The following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2011 Annual Report.

Cascade

At June 30, 2012, Cascade held a natural gas swap agreement, with total forward notional volumes of 123,000 MMBtu, which was not designated as a hedge. Cascade utilizes natural gas swap agreements to manage a portion of its regulated natural gas supply portfolio in order to manage fluctuations in the price of natural gas related to core customers in accordance with authority granted by the WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument 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. Periodic changes in the fair market value of the derivative instruments are recorded on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three and six months ended June 30, 2012, the change in the fair market value of the derivative instrument of $261,000 and $209,000, respectively, was recorded as a decrease to regulatory assets. For the three and six months ended June 30, 2011, the change in the fair market value of the derivative instruments of

$1.9 million and $8.5 million, respectively, was recorded as a decrease to regulatory assets.

Cascade's derivative instrument contains a cross-default provision that states if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparty could require early settlement or termination of such entity's derivative instrument in a liability position. The fair value of Cascade's derivative instrument with a credit-risk-related contingent feature that is in a liability position at June 30, 2012, was $228,000. The aggregate fair value of assets that would have been needed to settle the instrument immediately if the credit-risk-related contingent feature was triggered on June 30, 2012, was $228,000.

Fidelity

At June 30, 2012, Fidelity held oil swap and collar agreements with total forward notional volumes of 3.7 million Bbl, natural gas swap agreements with total forward notional volumes of 9.1 million MMBtu, and natural gas basis swap agreements with total forward notional volumes of 1.7 million MMBtu, a majority of which were designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas and basis differentials on its forecasted sales of oil and natural gas production.

As of June 30, 2012, the maximum term of the derivative instruments, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 18 months.

Centennial

At June 30, 2012, Centennial held interest rate swap agreements with a total notional amount of $60.0 million, which were designated as cash flow hedging instruments. Centennial entered into these interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt. Centennial's interest rate swap agreements have mandatory termination dates ranging from October 2012 through June 2013.

Fidelity and Centennial

The fair value of the 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 liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings.

For the three and six months ended June 30, 2012, a net gain of $3.9 million (before tax) and a net loss of $400,000 (before tax), respectively, of ineffectiveness on oil and natural gas derivatives that qualified for hedge accounting were reclassified into operating revenues and are reflected on the Consolidated Statements of Income. The amount of hedge ineffectiveness was immaterial for the three and six months ended June 30, 2011. For the three and six months ended June 30, 2012, gains of $1.0 million (before tax) and $1.0 million (before tax), respectively, and for the three and six months ended June 30, 2011, gains of $1.9 million (before tax) and $179,000 (before tax), respectively, related to derivative instruments that did not qualify for hedge accounting were reported in operating revenues on the Consolidated Statements of Income. 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.

Gains and losses on the oil and natural gas derivative instruments are reclassified from accumulated other comprehensive income (loss) into operating revenues on the Consolidated Statements of Income at the date the oil and natural gas quantities are settled. The proceeds received for oil and natural gas production are generally based on market prices. Gains and losses on the interest rate derivatives are reclassified from accumulated other comprehensive income (loss) into interest expense on the Consolidated Statements of Income in the same period the hedged item affects earnings. For more information regarding the gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in other comprehensive income (loss) and the gains and losses reclassified from accumulated other comprehensive income (loss) into earnings, see the Consolidated Statements of Comprehensive Income.

Based on June 30, 2012, fair values, over the next 12 months net gains of approximately $22.1 million (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in oil and natural gas market prices and interest rates, as the hedged transactions affect earnings.

Certain of Fidelity's and Centennial's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates or Centennial fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair

value of Fidelity's and Centennial's derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2012, was $7.8 million. 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 June 30, 2012, was $7.8 million.

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



Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at June 30, 2012		Fair Value at June 30, 2011		Fair Value at December 31, 2011
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	36,360	$	14,040	$	27,687
	Other assets - noncurrent	11,445		6,265		2,768
		47,805		20,305		30,455
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	640		194		—
	Other assets - noncurrent	212		—		—
		852		194		—
Total asset derivatives		$	48,657	$	20,499	$	30,455



Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at June 30, 2012		Fair Value at June 30, 2011		Fair Value at December 31, 2011
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	789	$	17,780	$	12,727
	Other liabilities - noncurrent	—		6,735		937
Interest rate derivatives	Other accrued liabilities	6,963		—		827
	Other liabilities - noncurrent	—		—		3,935
		7,752		24,515		18,426
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	248		906		437
	Other liabilities - noncurrent	—		—		—
		248		906		437
Total liability derivatives		$	8,000	$	25,421	$	18,863

Note 12 - 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 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 $46.0 million, $40.3 million and $38.4 million, as of June 30, 2012 and 2011, and December 31, 2011, respectively, are classified as Investments on the Consolidated Balance Sheets. The fair value of these investments decreased $2.7 million for the three months ended June 30, 2012, and increased $2.2 million for the six months ended June 30, 2012. The fair value of these investments decreased $1.3 million for the three months ended June 30, 2011, and increased $790,000 for the six months ended June 30, 2011. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

The Company did not elect the fair value option, which records gains and losses in income, for its remaining available-for-sale securities, which include auction rate securities, 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. The Company's auction rate securities approximated cost and, as a result, there were no accumulated unrealized gains or losses recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments. In the second quarter of 2012, the Company sold its auction rate securities at cost and did not realize any gains or losses. Unrealized gains or losses on mortgage-backed securities and U.S. Treasury securities are recorded in accumulated other comprehensive income (loss). Details of available-for-sale securities were as follows:



June 30, 2012	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Insurance investment contract	$	37,250	$	8,709	$	—		$	45,959
Mortgage-backed securities	8,130		128		(5		)	8,253
U.S. Treasury securities	1,958		37		(1		)	1,994
Total	$	47,338	$	8,874	$	(6	)	$	56,206



December 31, 2011	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Insurance investment contract	$	31,884	$	6,468	$	—		$	38,352
Auction rate securities	11,400		—		—			11,400
Mortgage-backed securities	8,206		95		(5		)	8,296
U.S. Treasury securities	1,619		37		—			1,656
Total	$	53,109	$	6,600	$	(5	)	$	59,704

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



	Fair Value Measurements at June 30, 2012, 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, 2012
	(In thousands)
Assets:
Money market funds	$	—	$	21,054	$	—	$	21,054
Available-for-sale securities:
Insurance investment contract*	—		45,959		—		45,959
Mortgage-backed securities	—		8,253		—		8,253
U.S. Treasury securities	—		1,994		—		1,994
Commodity derivative instruments	—		48,657		—		48,657
Total assets measured at fair value	$	—	$	125,917	$	—	$	125,917
Liabilities:
Commodity derivative instruments	$	—	$	1,037	$	—	$	1,037
Interest rate derivative instruments	—		6,963		—		6,963
Total liabilities measured at fair value	$	—	$	8,000	$	—	$	8,000

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



	Fair Value Measurements at June 30, 2011, 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, 2011
	(In thousands)
Assets:
Money market funds	$	—	$	8,297	$	—	$	8,297
Available-for-sale securities:
Insurance investment contract*	—		40,328		—		40,328
Auction rate securities	—		11,400		—		11,400
Mortgage-backed securities	—		8,162		—		8,162
U.S. Treasury securities	—		1,969		—		1,969
Commodity derivative instruments	—		20,499		—		20,499
Total assets measured at fair value	$	—	$	90,655	$	—	$	90,655
Liabilities:
Commodity derivative instruments	$	—	$	25,421	$	—	$	25,421
Total liabilities measured at fair value	$	—	$	25,421	$	—	$	25,421

* The insurance investment contract invests approximately 34 percent in common stock of mid-cap companies, 33 percent in common stock of small-cap companies, 32 percent in common stock of large-cap companies and 1 percent in cash and cash equivalents.



	Fair Value Measurements at December 31, 2011, 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, 2011
	(In thousands)
Assets:
Money market funds	$	—	$	97,500	$	—	$	97,500
Available-for-sale securities:
Insurance investment contract*	—		38,352		—		38,352
Auction rate securities	—		11,400		—		11,400
Mortgage-backed securities	—		8,296		—		8,296
U.S. Treasury securities	—		1,656		—		1,656
Commodity derivative instruments	—		30,455		—		30,455
Total assets measured at fair value	$	—	$	187,659	$	—	$	187,659
Liabilities:
Commodity derivative instruments	$	—	$	14,101	$	—	$	14,101
Interest rate derivative instruments	—		4,762		—		4,762
Total liabilities measured at fair value	$	—	$	18,863	$	—	$	18,863

* The insurance investment contract invests approximately 33 percent in common stock of mid-cap companies, 34 percent in common stock of small-cap companies, 32 percent in common stock of large-cap companies and 1 percent in cash and cash equivalents.

The estimated fair value of the Company's Level 2 money market funds and available-for-sale securities is determined using the market approach. The 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 available-for-sale securities is based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources such as the fund itself.

The estimated fair value of the Company's Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of 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 evaluated.

The estimated fair value of the Company's Level 2 interest rate derivative instruments is measured using quoted market prices or pricing models using prevailing market interest rates as of the measurement date. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties nonperformance risk is evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the three and six months ended June 30, 2012, there were no transfers between Levels 1 and 2.

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. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt was as follows:



	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at June 30, 2012	$	1,665,631	$	1,839,430
Long-term debt at June 30, 2011	$	1,432,105	$	1,550,592
Long-term debt at December 31, 2011	$	1,424,678	$	1,592,807

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

Note 13 - Income taxes

In connection with the income tax examination for the 2007 through 2009 tax years, the Company recorded income tax expense of $2.2 million for unrecognized tax positions in the first quarter of 2012.

In addition, the Company had a reduction of deferred income tax expense of $2.5 million in the first quarter of 2012, due to a deferred income tax rate reduction related to state income tax apportionment.

In the first quarter of 2011, the Company received favorable resolution of certain tax matters relating to the 2004 through 2006 tax years. As a result, the Company recorded an income tax benefit from continuing operations of $4.2 million. This resolution includes the effects of $2.8 million related to the reversal of unrecognized tax benefits that were previously established for the 2004 through 2006 tax years and associated interest of $600,000.

The settlement of federal and state audits is not anticipated within the next twelve months and, as a result, it is not expected that the unrecognized tax benefits will significantly increase or decrease within the next twelve months.

Note 14 - 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 vast majority of the Company's operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources' equity method 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 primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services.

The exploration and production segment is engaged in oil and natural gas acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico.

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 in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. 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.

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 and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in ECTE.

The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2011 Annual Report. Information on the Company's businesses was as follows:



Three Months Ended June 30, 2012	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	52,955	$	—		$	4,419
Natural gas distribution	116,844		—			(6,411		)
Pipeline and energy services	34,656		8,937			15,851
	204,455		8,937			13,859
Exploration and production	100,232		5,711			17,957
Construction materials and contracting	438,963		3,097			7,791
Construction services	223,858		219			8,684
Other	454		2,028			5,651
	763,507		11,055			40,083
Intersegment eliminations	—		(19,992		)	—
Total	$	967,962	$	—		$	53,942



Three Months Ended June 30, 2011	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	49,986	$	—		$	4,807
Natural gas distribution	164,626		—			1,902
Pipeline and energy services	59,926		12,504			4,772
	274,538		12,504			11,481
Exploration and production	87,390		25,392			21,326
Construction materials and contracting	375,613		—			4,980
Construction services	192,697		5,379			6,138
Other	519		2,301			971
	656,219		33,072			33,415
Intersegment eliminations	—		(45,576		)	—
Total	$	930,757	$	—		$	44,896



Six Months Ended June 30, 2012	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	110,918	$	—		$	11,978
Natural gas distribution	424,733		—			19,097
Pipeline and energy services	63,882		29,347			18,611
	599,533		29,347			49,686
Exploration and production	188,727		17,038			30,887
Construction materials and contracting	588,232		3,248			(17,141		)
Construction services	442,010		244			20,087
Other	2,267		2,355			6,042
	1,221,236		22,885			39,875
Intersegment eliminations	—		(52,232		)	—
Total	$	1,820,769	$	—		$	89,561



Six Months Ended June 30, 2011	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	107,831	$	—		$	13,331
Natural gas distribution	535,010		—			29,418
Pipeline and energy services	109,177		37,245			11,691
	752,018		37,245			54,440
Exploration and production	165,801		50,933			37,596
Construction materials and contracting	519,146		—			(16,423		)
Construction services	394,877		6,596			10,771
Other	720		4,589			1,318
	1,080,544		62,118			33,262
Intersegment eliminations	—		(99,363		)	—
Total	$	1,832,562	$	—		$	87,702

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 15 - Acquisitions

On May 18, 2012, the Company acquired a 50 percent undivided interest in natural gas and oil midstream assets in western North Dakota. The acquisition includes a natural gas processing plant and a natural gas gathering pipeline system, along with an oil gathering system, an oil storage terminal and an oil pipeline. The total purchase consideration for its interest in the facilities was approximately $66.0 million. The company recognizes its proportionate share of the assets, liabilities, revenues and expenses related to this acquisition. Proforma financial amounts reflecting the effects of the above acquisition have not been presented, as the acquisition was not material to the Company's financial position or results of operations.

Note 16 - Employee benefit 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 June 30,	2012			2011			2012			2011
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	350		$	827		$	461		$	383
Interest cost	4,262			4,959			1,038			1,161
Expected return on assets	(5,845		)	(5,727		)	(1,201		)	(1,308		)
Amortization of prior service cost (credit)	(21		)	44			(272		)	(669		)
Amortization of net actuarial (gain) loss	2,102			1,049			887			(53		)
Amortization of net transition obligation	—			—			531			531
Curtailment loss	—			1,218			—			—
Net periodic benefit cost, including amount capitalized	848			2,370			1,444			45
Less amount capitalized	196			287			183			(28		)
Net periodic benefit cost	$	652		$	2,083		$	1,261		$	73

							Other
							Postretirement
	Pension Benefits						Benefits
Six Months Ended June 30,	2012			2011			2012			2011
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	695		$	1,654		$	873		$	722
Interest cost	8,816			9,919			2,181			2,350
Expected return on assets	(11,731		)	(11,427		)	(2,445		)	(2,526		)
Amortization of prior service cost (credit)	(42		)	87			(544		)	(1,338		)
Amortization of net actuarial loss	3,783			2,592			1,413			258
Amortization of net transition obligation	—			—			1,063			1,062
Curtailment loss	—			1,218			—			—
Net periodic benefit cost, including amount capitalized	1,521			4,043			2,541			528
Less amount capitalized	430			535			321			(95		)
Net periodic benefit cost	$	1,091		$	3,508		$	2,220		$	623

Defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005, were discontinued. Employees that would have been eligible for defined pension plan benefits are eligible to receive additional defined contribution plan benefits. Effective January 1, 2010, all benefit and service accruals for nonunion and certain union plans were frozen. Effective June 30, 2011, all benefit and service accruals for an additional union plan were frozen. These employees will be eligible to receive additional defined contribution plan benefits.

In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides 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 for the three and six months ended June 30, 2012, was $2.0 million and $4.1 million, respectively. The Company's net periodic benefit cost for this plan for the three and six months ended June 30, 2011, was $1.9 million and $4.0 million, respectively.

Note 17 - Regulatory matters and revenues subject to refund

On May 20, 2011, Montana-Dakota filed an application with the NDPSC requesting advance determination of prudence that the addition of the air quality control system at the Big Stone Station, to comply with the Clean Air Act and the South Dakota Regional Haze Implementation Plan, is reasonable and prudent. A hearing was held on November 29, 2011. On May 9, 2012,

the NDPSC issued an order approving the advance determination of prudence.

On July 7, 2011, Montana-Dakota filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities projected to be in service in 2015. The turbine will be located on company-owned property that is adjacent to Montana-Dakota's Heskett Generating Station near Mandan, North Dakota, and would be used to meet the capacity requirements of Montana-Dakota's integrated electric system service customers. The capacity will be a partial replacement for third party contract capacity expiring in 2015. Project cost is estimated to be $85.6 million. On April 11, 2012, the NDPSC issued an order approving the advance determination of prudence and issued a Certificate of Public Convenience and Necessity.

On November 15, 2011, the MNPUC issued a Notice of Investigation; Opportunity to Respond and Comment to investigate whether Great Plains' rates are unreasonable and whether Great Plains should be ordered to initiate a general rate proceeding as Great Plains has earned in excess of its authorized return and the excess earnings are likely to continue into the future. On December 2, 2011, Great Plains responded to the MNPUC's Notice. On January 30, 2012, the MNPUC issued an order that found that the reasonableness of Great Plains' rates had not been resolved to the MNPUC's satisfaction and required Great Plains to initiate a rate proceeding within 180 days of the order, unless resolved through settlement. On March 30, 2012, Great Plains and the MNDOC filed a settlement agreement with the MNPUC, in which Great Plains agreed to reduce its rates by $250,000 annually. The MNPUC approved the settlement agreement on April 26, 2012, with the revenue reduction implemented effective with service rendered on and after June 1, 2012.

Note 18 - 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, where feasible, an estimate of the possible loss. The Company had accrued liabilities of $48.1 million, $40.7 million and $64.1 million for contingencies related to litigation and environmental matters as of June 30, 2012 and 2011, and December 31, 2011, respectively, which includes amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

Litigation

Guarantee Obligation Under a Construction Contract Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent. In February 2009, Centennial received a Notice and Demand from LPP under the guarantee agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM's alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association. The demand sought compensatory damages of $149.7 million. In June 2010, CEM and Bicent made a demand on Centennial Resources for indemnification under the 2007 purchase and sale agreement for indemnifiable losses, including defense fees and costs arising from LPP's arbitration demand and related to Centennial Resources' ownership of CEM prior to its sale to Bicent. Centennial and Centennial Resources filed a complaint with the New York Supreme Court in November 2010, against Bicent seeking damages for breach of contract and other relief. On September 19, 2011, Bicent filed a counterclaim seeking damages against Centennial Resources related to Bicent's costs of defending the LPP arbitration demand which Bicent alleged were in excess of $14.0 million. Bicent and its affiliates, including CEM, filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on April 23, 2012, which stayed the New York Supreme Court action. The arbitration hearing on LPP's claim was held in the third quarter of 2011, and an arbitration award was issued January 13, 2012, awarding LPP $22.0 million. Centennial subsequently received a demand from LPP for payment of the arbitration award plus interest and attorneys' fees. An accrual related to the guarantee as a result of the arbitration award was recorded in discontinued operations on the Consolidated Statement of Income in the fourth quarter of 2011. Centennial Resources and Bicent reached agreement on settlement of their claims and dismissal of the New York Supreme Court action subject to approval by the bankruptcy court. The settlement did not have a material effect on the consolidated financial statements for the three and six months ended June 30, 2012. For more information regarding discontinued operations, see Note 8.

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.

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. An arbitration hearing was held in August 2010. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, WBI Energy Midstream, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010. On April 20, 2011, the Colorado State District Court confirmed the arbitration award as a court judgment. WBI Energy Midstream filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals. 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. As a result of the Colorado Court of Appeals decision, in the second quarter of 2012, WBI Energy Midstream recorded a net benefit of $24.1 million ($15.0 million after tax), which is largely reflected in operation and maintenance expense on the Consolidated Statements of Income, related to this matter because the incurrence of a loss for the arbitration award is not probable. On August 2, 2012, SourceGas filed a petition for writ of certiorari with the Colorado Supreme Court for review of the Colorado Court of Appeals decision. WBI Energy Midstream anticipates that on remand to the Colorado State District Court, SourceGas will 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. Expert reports submitted by Omimex contend its damages as a result of the increased operating pressures are $16.1 million to $22.6 million. The Company believes the claims asserted by Omimex are without merit and an award is not deemed probable. The Company intends to vigorously defend against the claims.

The Company also is involved in other legal actions in the ordinary course of its business. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above and other legal proceedings 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 is preparing a staff report which will recommend a cleanup alternative for the site. 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. Cascade has accrued $1.3 million for remediation of this site.

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. 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. Cascade is in discussions with the EPA regarding an administrative settlement agreement and consent order with the intent of reaching consensus on the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $6.4 million for the remedial investigation and feasibility study and $6.4 million for 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 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.

Guarantees

Centennial guaranteed CEM's obligations under a construction contract. For more information, see Litigation in this note.

In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 9, 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 and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap and collar agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap and collar agreements at June 30, 2012, expire in the years ranging from 2012 to 2013; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. There were no amounts outstanding by Fidelity at June 30, 2012. 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 June 30, 2012, the fixed maximum amounts guaranteed under these agreements aggregated $87.3 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $7.9 million in 2012; $62.4 million in 2013; $300,000 in 2014; $100,000 in 2015; $100,000 in 2016; $700,000 in 2018; $300,000 in 2019; $11.5 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 $500,000 and was reflected on the Consolidated Balance Sheet at June 30, 2012. 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, natural gas transportation agreements and other agreements, some of which are guaranteed by other subsidiaries of the Company. At June 30, 2012, the fixed maximum amounts guaranteed under these letters of credit, aggregated $27.5 million. In 2012 and 2013, $20.2 million and $7.3 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at June 30, 2012.

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 June 30, 2012, the fixed maximum amount guaranteed under this agreement was $5.0 million and is scheduled to expire in 2014. 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 $1.1 million. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at June 30, 2012, 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 June 30, 2012.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries, as well as an arbitration award. 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. As of June 30, 2012, approximately $604 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

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

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. 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 certain related business challenges are summarized below. For a summary of the Company's business segments, see Note 14.

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities for growth and expansion of their customer base through extensions of existing operations, including building electric generation, transmission extensions, 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 permitted returns on investment as well as subject to certain operational and environmental regulations. 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, 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 facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing activities; and expansion of related energy services.

Challenges Challenges for this segment include: energy price volatility; 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 Apply technology and utilize existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities both in new and existing areas to further expand the segment's asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment is focused on balancing the oil and gas commodity mix to maximize profitability with its goal to add value by increasing both reserves and production over the long term so as to generate competitive returns on investment.

Challenges 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; inflationary pressure on development and operating costs; 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; and continue growth through organic and acquisition opportunities. Ongoing efforts to increase margin are being pursued through the implementation of a variety of continuous improvement programs, including corporate purchasing of equipment, parts and commodities (liquid asphalt, diesel fuel, cement and other materials), and negotiation of contract price escalation provisions. 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 The economic downturn continues to impact operations, particularly in the private construction market. Volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, continue to be a concern. 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 competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; focusing business development efforts on project areas that will permit higher margins; and 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.

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 2011 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.

Earnings Overview

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Dollars in millions, where applicable)
Electric	$	4.4		$	4.8		$	12.0		$	13.3
Natural gas distribution	(6.4		)	1.9			19.1			29.4
Pipeline and energy services	15.8			4.8			18.6			11.7
Exploration and production	18.0			21.3			30.9			37.6
Construction materials and contracting	7.8			5.0			(17.1		)	(16.4		)
Construction services	8.7			6.1			20.1			10.8
Other	.5			1.1			1.0			1.1
Earnings before discontinued operations	48.8			45.0			84.6			87.5
Income (loss) from discontinued operations, net of tax	5.1			(.1		)	5.0			.2
Earnings on common stock	$	53.9		$	44.9		$	89.6		$	87.7
Earnings per common share - basic:
Earnings before discontinued operations	$	.26		$	.24		$	.45		$	.46
Discontinued operations, net of tax	.03			—			.02			—
Earnings per common share - basic	$	.29		$	.24		$	.47		$	.46
Earnings per common share - diluted:
Earnings before discontinued operations	$	.26		$	.24		$	.45		$	.46
Discontinued operations, net of tax	.03			—			.02			—
Earnings per common share - diluted	$	.29		$	.24		$	.47		$	.46
Return on average common equity for the 12 months ended							7.7		%	8.9		%

Three Months Ended June 30, 2012 and 2011 Consolidated earnings for the quarter ended June 30, 2012, increased $9.0 million from the comparable prior period largely due to:


•	A net benefit related to the natural gas gathering operations litigation of $15.0 million (after tax), as discussed in Note 18, at the pipeline and energy services business


•	Income from discontinued operations of $5.1 million (after tax), as discussed in Note 8

Partially offsetting these increases were decreased retail sales volumes, higher operation and maintenance expense, as well as higher income taxes at the natural gas distribution business.

Six Months Ended June 30, 2012 and 2011 Consolidated earnings for the six months ended June 30, 2012, increased $1.9 million from the comparable prior period largely due to:


•	Higher workloads and margins in the Central and Western regions, higher equipment sales and rental margins, as well as higher margins in the Mountain region, partially offset by higher general and administrative expense at the construction services business


•	Lower operation and maintenance expense, as previously discussed, partially offset by lower gathering volumes and lower storage services revenue at the pipeline and energy services business


•	Income from discontinued operations of $5.0 million (after tax), as previously discussed

Partially offsetting these increases were:


•	Decreased retail sales volumes, higher operation and maintenance expense, as well as higher income taxes at the natural gas distribution business


•	Lower average realized natural gas prices, decreased natural gas production and higher depreciation, depletion and amortization expense, partially offset by increased oil production, lower gathering and transportation expense and lower production taxes at the exploration and production business

FINANCIAL AND OPERATING DATA

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

Electric



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Dollars in millions, where applicable)
Operating revenues	$	53.0	$	50.0	$	110.9	$	107.8
Operating expenses:
Fuel and purchased power	15.2		14.5		33.6		31.4
Operation and maintenance	19.1		18.3		35.3		34.3
Depreciation, depletion and amortization	8.0		7.9		16.1		16.1
Taxes, other than income	2.6		2.5		5.3		5.0
	44.9		43.2		90.3		86.8
Operating income	8.1		6.8		20.6		21.0
Earnings	$	4.4	$	4.8	$	12.0	$	13.3
Retail sales (million kWh)	666.3		614.6		1,436.0		1,409.3
Sales for resale (million kWh)	1.0		21.8		2.9		28.5
Average cost of fuel and purchased power per kWh	$	.021	$	.021	$	.022	$	.021

Three Months Ended June 30, 2012 and 2011 Electric earnings decreased $400,000 (8 percent) due to:


•	Higher income taxes of $1.3 million, primarily related to the absence of the reduction of deferred income taxes associated with benefits in 2011


•	Higher operation and maintenance expense of $600,000 (after tax), including increased contract services at certain of the Company's electric generation stations

The earnings decrease was partially offset by higher retail sales volumes of 8 percent, primarily to small commercial and industrial customers and residential customers, reflecting increased demand due to warmer weather than last year, as well as increased customer growth.

Six Months Ended June 30, 2012 and 2011 Electric earnings decreased $1.3 million (10 percent) due to:


•	Higher income taxes of $1.8 million, primarily related to the absence of the reduction of deferred income taxes as previously discussed, as well as the absence of an income tax benefit related to favorable resolution of certain income tax matters in 2011


•	Higher operation and maintenance expense of $600,000 (after tax), as previously discussed

Partially offsetting these decreases were increased retail sales volumes of 2 percent, primarily to small commercial and industrial customers, as previously discussed.

Natural Gas Distribution



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Dollars in millions, where applicable)
Operating revenues	$	116.8		$	164.6		$	424.7		$	535.0
Operating expenses:
Purchased natural gas sold	62.9			102.0			262.2			359.4
Operation and maintenance	35.9			33.3			71.1			67.6
Depreciation, depletion and amortization	11.3			11.2			22.5			22.4
Taxes, other than income	10.0			10.6			26.2			28.4
	120.1			157.1			382.0			477.8
Operating income (loss)	(3.3		)	7.5			42.7			57.2
Earnings (loss)	$	(6.4	)	$	1.9		$	19.1		$	29.4
Volumes (MMdk):
Sales	13.4			17.3			52.1			61.3
Transportation	26.8			25.6			64.7			59.7
Total throughput	40.2			42.9			116.8			121.0
Degree days (% of normal)*
Montana-Dakota	77		%	120		%	77		%	112		%
Cascade	94		%	118		%	99		%	107		%
Intermountain	97		%	141		%	94		%	113		%
Average cost of natural gas, including transportation, per dk	$	4.70		$	5.88		$	5.03		$	5.87
* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended June 30, 2012 and 2011 The natural gas distribution business recognized a loss of $6.4 million compared to earnings of $1.9 million for the comparable prior period due to:


•	Lower earnings of $4.4 million (after tax) related to decreased retail sales volumes, largely resulting from significantly warmer weather than last year


•	Higher operation and maintenance expense of $1.9 million (after tax), including higher benefit and payroll-related costs


•	Higher income taxes of $1.5 million, primarily related to the absence of a reduction of deferred income taxes associated with benefits in 2011

Six Months Ended June 30, 2012 and 2011 Earnings at the natural gas distribution business decreased $10.3 million (35 percent) due to:


•	Lower earnings of $7.0 million (after tax) related to decreased retail sales volumes, largely resulting from significantly warmer weather than last year, partially offset by weather normalization adjustments in certain jurisdictions


•	Higher operation and maintenance expense of $1.9 million (after tax), as previously discussed


•	Higher income taxes of $1.6 million, as previously discussed

Pipeline and Energy Services



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012				2011		2012			2011
	(Dollars in millions)
Operating revenues	$	43.6			$	72.4	$	93.2		$	146.4
Operating expenses:
Purchased natural gas sold	8.5				33.9		24.6			68.0
Operation and maintenance	(1.4		)	*	18.6		15.6		*	36.2
Depreciation, depletion and amortization	6.8				6.4		13.1			12.8
Taxes, other than income	3.5				3.4		6.9