10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended March 31, 2014

OR

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

For the Transition Period from _____________ to ______________

Commission file number 1-3480

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 April 30, 2014: 191,604,704 shares.

DEFINITIONS

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

Abbreviation or Acronym
2013 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2013
ASC	FASB Accounting Standards Codification
BART	Best available retrofit technology
Bbl	Barrel
Bicent	Bicent Power LLC
Big Stone Station	475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BLM	Bureau of Land Management
BOE	One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
BOPD	Barrels of oil per day
Brazilian Transmission Lines	Company's 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 third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010)
Btu	British thermal unit
Calumet	Calumet Specialty Products Partners, L.P.
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CCU	Cane Creek Unit
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
Coyote Creek	Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station	427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery	20,000-barrel-per-day diesel topping plant being built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining	Dakota Prairie Refining, LLC, a limited liability company jointly owned by WBI Energy and Calumet
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA	Earnings before interest, taxes, depreciation, depletion and amortization
ECTE	Empresa Catarinense de Transmissão de Energia S.A. (2.5 percent ownership interest at March 31, 2014, 2.5, 2.5, 2.5 and 14.99 percent ownership interests were sold in the third quarters of 2013 and 2012 and the fourth quarters of 2011 and 2010, respectively)
ENTE	Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
EPA	U.S. Environmental Protection Agency
ERTE	Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
Fidelity Oil Co.	A direct wholly owned subsidiary of Fidelity
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital

2

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
MISO	Midcontinent Independent System Operator, Inc.
MMBbls	Millions of barrels
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million decatherms
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
MW	Megawatt
NDPSC	North Dakota Public Service Commission
New York Supreme Court	Supreme Court of the State of New York, County of New York
NGL	Natural gas liquids
NSPS	New Source Performance Standards
Oil	Includes crude oil and condensate
Omimex	Omimex Canada, Ltd.
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PRP	Potentially Responsible Party
RCRA	Resource Conservation and Recovery Act
ROD	Record of Decision
SEC	U.S. Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
SourceGas	SourceGas Distribution LLC
VIE	Variable interest entity
WBI Energy	WBI Energy, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Midstream	WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings (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

3

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 16.

4

INDEX

Part I -- Financial Information	Page
Consolidated Statements of Income -- Three Months Ended March 31, 2014 and 2013	6
Consolidated Statements of Comprehensive Income -- Three Months Ended March 31, 2014 and 2013	7
Consolidated Balance Sheets -- March 31, 2014 and 2013, and December 31, 2013	8
Consolidated Statements of Cash Flows -- Three Months Ended March 31, 2014 and 2013	9
Notes to Consolidated Financial Statements	10
Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Quantitative and Qualitative Disclosures About Market Risk	45
Controls and Procedures	46
Part II -- Other Information
Legal Proceedings	46
Risk Factors	46
Unregistered Sales of Equity Securities and Use of Proceeds	48
Mine Safety Disclosures	48
Exhibits	48
Signatures	49
Exhibit Index	50
Exhibits

5

PART I -- FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
	(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$	491,541		$	424,124
Exploration and production, construction materials and contracting, construction services and other	551,312			507,480
Total operating revenues	1,042,853			931,604
Operating expenses:
Fuel and purchased power	26,544			21,608
Purchased natural gas sold	244,892			199,187
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	67,284			66,101
Exploration and production, construction materials and contracting, construction services and other	445,951			394,019
Depreciation, depletion and amortization	99,557			93,561
Taxes, other than income	55,721			52,597
Total operating expenses	939,949			827,073
Operating income	102,904			104,531
Earnings (loss) from equity method investments	51			(311		)
Other income	2,132			1,242
Interest expense	20,971			20,874
Income before income taxes	84,116			84,588
Income taxes	27,932			27,996
Income from continuing operations	56,184			56,592
Loss from discontinued operations, net of tax (Note 9)	(45		)	(77		)
Net income	56,139			56,515
Net loss attributable to noncontrolling interest	(523		)	—
Dividends declared on preferred stocks	171			171
Earnings on common stock	$	56,491		$	56,344
Earnings per common share - basic:
Earnings before discontinued operations	$	.30		$	.30
Discontinued operations, net of tax	—			—
Earnings per common share - basic	$	.30		$	.30
Earnings per common share - diluted:
Earnings before discontinued operations	$	.30		$	.30
Discontinued operations, net of tax	—			—
Earnings per common share - diluted	$	.30		$	.30
Dividends declared per common share	$	.1775		$	.1725
Weighted average common shares outstanding - basic	189,820			188,831
Weighted average common shares outstanding - diluted	190,432			189,222

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

6

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Net income	$	56,139		$	56,515
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $0 and $(3,168) for the three months ended in 2014 and 2013, respectively	—			(5,849		)
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $204 and $(1,626) for the three months ended in 2014 and 2013, respectively	344			(2,772		)
Net unrealized gain (loss) on derivative instruments qualifying as hedges	344			(8,621		)
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $168 and $319 for the three months ended in 2014 and 2013, respectively	275			648
Foreign currency translation adjustment recognized during the period, net of tax of $28 and $37 for the three months ended in 2014 and 2013, respectively	46			88
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(19) and $(24) for the three months ended in 2014 and 2013, respectively	(36		)	(44		)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $20 and $19 for the three months ended in 2014 and 2013, respectively	38			35
Net unrealized gain (loss) on available-for-sale investments	2			(9		)
Other comprehensive income (loss)	667			(7,894		)
Comprehensive income	56,806			48,621
Comprehensive loss attributable to noncontrolling interest	(523		)	—
Comprehensive income attributable to common stockholders	$	57,329		$	48,621

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

7

MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2014			March 31, 2013			December 31, 2013
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	83,700		$	74,149		$	45,225
Receivables, net	690,761			635,564			713,067
Inventories	301,332			334,872			282,391
Deferred income taxes	29,427			29,885			25,048
Commodity derivative instruments	81			5,936			1,447
Prepayments and other current assets	99,229			68,828			49,510
Total current assets	1,204,530			1,149,234			1,116,688
Investments	113,763			106,846			112,939
Property, plant and equipment	9,150,269			8,303,065			8,803,866
Less accumulated depreciation, depletion and amortization	3,954,442			3,678,535			3,872,487
Net property, plant and equipment	5,195,827			4,624,530			4,931,379
Deferred charges and other assets:
Goodwill	636,039			636,039			636,039
Other intangible assets, net	12,296			16,318			13,099
Other	246,394			295,215			251,188
Total deferred charges and other assets	894,729			947,572			900,326
Total assets	$	7,408,849		$	6,828,182		$	7,061,332
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	37,500		$	11,500
Long-term debt due within one year	12,227			171,094			12,277
Accounts payable	399,935			375,942			404,961
Taxes payable	61,847			55,748			74,175
Dividends payable	33,980			32,744			33,737
Accrued compensation	40,016			31,382			69,661
Commodity derivative instruments	12,186			7,379			7,483
Other accrued liabilities	185,287			205,394			171,106
Total current liabilities	745,478			917,183			784,900
Long-term debt	2,093,605			1,618,569			1,842,286
Deferred credits and other liabilities:
Deferred income taxes	899,420			802,805			859,306
Other liabilities	720,542			814,643			718,938
Total deferred credits and other liabilities	1,619,962			1,617,448			1,578,244
Commitments and contingencies
Equity:
Preferred stocks	15,000			15,000			15,000
Common stockholders' equity:
Common stock
Authorized - 500,000,000 shares, $1.00 par value
Shares issued - 191,838,720 at March 31, 2014, 189,369,450 at March 31, 2013 and 189,868,780 at December 31, 2013	191,839			189,369			189,869
Other paid-in capital	1,110,221			1,038,970			1,056,996
Retained earnings	1,625,692			1,480,784			1,603,130
Accumulated other comprehensive loss	(37,538		)	(56,615		)	(38,205		)
Treasury stock at cost - 538,921 shares	(3,626		)	(3,626		)	(3,626		)
Total common stockholders' equity	2,886,588			2,648,882			2,808,164
Total stockholders' equity	2,901,588			2,663,882			2,823,164
Noncontrolling interest	48,216			11,100			32,738
Total equity	2,949,804			2,674,982			2,855,902
Total liabilities and equity	$	7,408,849		$	6,828,182		$	7,061,332

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

8

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Operating activities:
Net income	$	56,139		$	56,515
Loss from discontinued operations, net of tax	(45		)	(77		)
Income from continuing operations	56,184			56,592
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	99,557			93,561
Earnings (loss), net of distributions, from equity method investments	(51		)	1,277
Deferred income taxes	35,965			44,663
Unrealized loss on commodity derivatives	6,712			5,832
Changes in current assets and liabilities, net of acquisitions:
Receivables	25,611			32,206
Inventories	(19,809		)	(19,126		)
Other current assets	(22,324		)	(25,855		)
Accounts payable	(11,525		)	(35,091		)
Other current liabilities	(28,355		)	(7,338		)
Other noncurrent changes	(4,936		)	(10,150		)
Net cash provided by continuing operations	137,029			136,571
Net cash provided by discontinued operations	8			303
Net cash provided by operating activities	137,037			136,874
Investing activities:
Capital expenditures	(179,646		)	(188,475		)
Acquisitions, net of cash acquired	(206,304		)	—
Net proceeds from sale or disposition of property and other	5,179			18,176
Investments	458			(514		)
Net cash used in continuing operations	(380,313		)	(170,813		)
Net cash provided by discontinued operations	—			—
Net cash used in investing activities	(380,313		)	(170,813		)
Financing activities:
Issuance of short-term borrowings	—			9,300
Repayment of short-term borrowings	(11,500		)	—
Issuance of long-term debt	309,501			112,015
Repayment of long-term debt	(58,232		)	(67,123		)
Proceeds from issuance of common stock	54,843			—
Dividends paid	(33,737		)	(171		)
Excess tax benefit on stock-based compensation	4,833			—
Contribution from noncontrolling interest	16,000			5,000
Net cash provided by continuing operations	281,708			59,021
Net cash provided by discontinued operations	—			—
Net cash provided by financing activities	281,708			59,021
Effect of exchange rate changes on cash and cash equivalents	43			25
Increase in cash and cash equivalents	38,475			25,107
Cash and cash equivalents -- beginning of year	45,225			49,042
Cash and cash equivalents -- end of period	$	83,700		$	74,149

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

9

MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

March 31, 2014 and 2013

(Unaudited)

Note 1 - Basis of presentation

The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2013 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2013 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 March 31, 2014, 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 consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $22.6 million, $39.6 million and $36.4 million at March 31, 2014 and 2013, and December 31, 2013, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at March 31, 2014 and 2013, and December 31, 2013, was $10.9 million, $10.8 million and $10.1 million, respectively.

Note 4 - Inventories and natural gas in storage

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

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
Aggregates held for resale	$	104,106	$	98,120	$	101,568
Asphalt oil	66,292		94,332		38,099
Materials and supplies	68,809		75,868		69,808
Merchandise for resale	22,463		24,342		21,720
Natural gas in storage (current)	6,129		12,811		16,417
Other	33,533		29,399		34,779
Total	$	301,332	$	334,872	$	282,391

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, is included in other assets and was $47.4 million, $49.6 million, and $48.3 million at March 31, 2014 and 2013, and December 31, 2013, respectively.

10

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 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 calculations was as follows:

	Three Months Ended
	March 31,
	2014	2013
	(In thousands)
Weighted average common shares outstanding - basic	189,820	188,831
Effect of dilutive performance share awards	612	391
Weighted average common shares outstanding - diluted	190,432	189,222
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:

	Three Months Ended
	March 31,
	2014		2013
	(In thousands)
Interest, net of amount capitalized	$	20,850	$	21,857
Income taxes paid (refunded), net	$	9,435	$	(7,246	)

Noncash investing transactions were as follows:

	March 31,
	2014		2013
	(In thousands)
Property, plant and equipment additions in accounts payable	$	65,736	$	92,236

Note 7 - Comprehensive income (loss)

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2014, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)
Other comprehensive income (loss) before reclassifications	—			—			46			(36		)	10
Amounts reclassified from accumulated other comprehensive loss	344			275			—			38			657
Net current-period other comprehensive income	344			275			46			2			667
Balance at March 31, 2014	$	(3,421	)	$	(33,532	)	$	(621	)	$	36		$	(37,538	)

11

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2013, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
Other comprehensive income (loss) before reclassifications	(5,849		)	—			88			(44		)	(5,805		)
Amounts reclassified from accumulated other comprehensive loss	(2,772		)	648			—			35			(2,089		)
Net current-period other comprehensive income (loss)	(8,621		)	648			88			(9		)	(7,894		)
Balance at March 31, 2013	$	(2,603	)	$	(53,699	)	$	(423	)	$	110		$	(56,615	)

Reclassifications out of accumulated other comprehensive loss were as follows:

	Three Months Ended						Location on Consolidated Statements of Income
	March 31, 2014			March 31, 2013
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	(388	)	$	4,513		Operating revenues
Interest rate derivative instruments	(160		)	(115		)	Interest expense
	(548		)	4,398
	204			(1,626		)	Income taxes
	(344		)	2,772
Amortization of postretirement liability losses included in net periodic benefit cost	(443		)	(967		)	(a)
	168			319			Income taxes
	(275		)	(648		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(58		)	(54		)	Other income
	20			19			Income taxes
	(38		)	(35		)
Total reclassifications	$	(657	)	$	2,089

(a) Included in net periodic benefit cost (credit). For more information, see Note 17.

Note 8 - Acquisition

On February 10, 2014, the Company entered into agreements to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming. The effective date of the acquisition was October 1, 2013, and the closing occurred on March 6, 2014. The purchase price was $206.3 million, including purchase price adjustments.

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

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Note 9 - Discontinued operations

In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources had 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, which are reflected as discontinued operations in the consolidated financial statements and accompanying notes, and has accrued liabilities related to this matter. Discontinued operations are included in the Other category. For more information, see Note 19.

Note 10 - Equity method investments

Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At March 31, 2014, the Company had no significant equity method investments.

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

At March 31, 2013, the equity method investments had total assets of $142.9 million and long-term debt of $63.9 million. The Company's investment in its equity method investments was approximately $5.7 million, including undistributed earnings of $2.2 million, at March 31, 2013.

Note 11 - Goodwill and other intangible assets

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

Three Months Ended March 31, 2014	Balance as of January 1, 2014*		Goodwill Acquired During the Year		Balance as of March 31, 2014*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

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Three Months Ended March 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of March 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Year Ended December 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of December 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Other amortizable intangible assets were as follows:

	March 31, 2014			March 31, 2013			December 31, 2013
	(In thousands)
Customer relationships	$	21,310		$	21,310		$	21,310
Accumulated amortization	(14,230		)	(12,211		)	(13,726		)
	7,080			9,099			7,584
Noncompete agreements	5,580			7,236			6,186
Accumulated amortization	(4,335		)	(5,439		)	(4,840		)
	1,245			1,797			1,346
Other	10,920			10,979			10,995
Accumulated amortization	(6,949		)	(5,557		)	(6,826		)
	3,971			5,422			4,169
Total	$	12,296		$	16,318		$	13,099

Amortization expense for amortizable intangible assets for the three months ended March 31, 2014 and 2013, was $800,000 and $800,000, respectively. Estimated amortization expense for amortizable intangible assets is $3.2 million in 2014, $2.5 million in 2015, $2.2 million in 2016, $2.0 million in 2017, $1.0 million in 2018 and $2.2 million thereafter.

Note 12 - 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 March 31, 2014, the Company had no outstanding foreign currency or interest rate hedges.

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

Fidelity

At March 31, 2014 and 2013, and December 31, 2013, Fidelity held oil swap and collar agreements with total forward notional volumes of 2.7 million, 2.8 million and 2.9 million Bbl, respectively, and natural gas swap agreements with total forward

14

notional volumes of 14.7 million, 25.9 million and 18.3 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date. The Company expects to reclassify into earnings from accumulated other comprehensive income (loss) the remaining value related to de-designating commodity derivative instruments over the next 9 months.

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

Centennial

As of March 31, 2014 and December 31, 2013, Centennial had no outstanding interest rate swap agreements. At March 31, 2013, Centennial held interest rate swap agreements with total notional amounts of $40.0 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.

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. 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.

Fidelity and Centennial

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.

15

The gains and losses on derivative instruments were as follows:

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax	$	—		$	(6,154	)
Amount of (gain) loss reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	244			(2,843		)
Amount of loss recognized in operating revenues (ineffective portion), before tax	—			(1,422		)
Interest rate derivatives designated as cash flow hedges:
Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax	—			305
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	100			71
Amount of loss recognized in interest expense (ineffective portion), before tax	—			(159		)
Commodity derivatives not designated as hedging instruments:
Amount of loss recognized in operating revenues, before tax	(6,712		)	(4,410		)

Over the next 12 months net losses of approximately $449,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, 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 the 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 March 31, 2014 and 2013, and December 31, 2013, were $12.2 million, $12.4 million and $7.5 million, respectively. 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 March 31, 2014 and 2013, and December 31, 2013, were $12.2 million, $12.4 million and $7.5 million, respectively.

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

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	1,623	$	—
		—		1,623		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	81		4,313		1,447
	Other assets - noncurrent	249		243		503
		330		4,556		1,950
Total asset derivatives		$	330	$	6,179	$	1,950

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	5,994	$	—
	Other liabilities - noncurrent	—		534		—
Interest rate derivatives	Other accrued liabilities	—		4,458		—
		—		10,986		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	12,186		1,385		7,483
	Other liabilities - noncurrent	—		74		—
		12,186		1,459		7,483
Total liability derivatives		$	12,186	$	12,445	$	7,483

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

March 31, 2014	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	330	$	(330	)	$	—
Total assets	$	330	$	(330	)	$	—
Liabilities:
Commodity derivatives	$	12,186	$	(330	)	$	11,856
Total liabilities	$	12,186	$	(330	)	$	11,856

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March 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	6,179	$	(3,578	)	$	2,601
Total assets	$	6,179	$	(3,578	)	$	2,601
Liabilities:
Commodity derivatives	$	7,987	$	(3,578	)	$	4,409
Interest rate derivatives	4,458		—			4,458
Total liabilities	$	12,445	$	(3,578	)	$	8,867

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

Note 13 - Fair value measurements

The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $63.3 million, $53.3 million and $62.4 million, as of March 31, 2014 and 2013, and December 31, 2013, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were $900,000 and $4.4 million for the three months ended March 31, 2014 and 2013, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

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

March 31, 2014	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	7,943	$	63	$	(17	)	$	7,989
U.S. Treasury securities	2,069		9		—			2,078
Total	$	10,012	$	72	$	(17	)	$	10,067

March 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,749	$	133	$	(3	)	$	8,879
U.S. Treasury securities	1,301		39		—			1,340
Total	$	10,050	$	172	$	(3	)	$	10,219

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December 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

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

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

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

The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

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

The estimated fair value of the Company's Level 2 commodity derivative instruments 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 also 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 also 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 months ended March 31, 2014 and 2013, there were no transfers between Levels 1 and 2.

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

	Fair Value Measurements at March 31, 2014, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2014
	(In thousands)
Assets:
Money market funds	$	—	$	20,267	$	—	$	20,267
Insurance contract*	—		63,269		—		63,269
Available-for-sale securities:
Mortgage-backed securities	—		7,989		—		7,989
U.S. Treasury securities	—		2,078		—		2,078
Commodity derivative instruments	—		330		—		330
Total assets measured at fair value	$	—	$	93,933	$	—	$	93,933
Liabilities:
Commodity derivative instruments	$	—	$	12,186	$	—	$	12,186
Total liabilities measured at fair value	$	—	$	12,186	$	—	$	12,186

*  The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 27 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 16 percent in fixed-income investments.

	Fair Value Measurements at March 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	31,281	$	—	$	31,281
Insurance contract*	—		53,334		—		53,334
Available-for-sale securities:
Mortgage-backed securities	—		8,879		—		8,879
U.S. Treasury securities	—		1,340		—		1,340
Commodity derivative instruments	—		6,179		—		6,179
Total assets measured at fair value	$	—	$	101,013	$	—	$	101,013
Liabilities:
Commodity derivative instruments	$	—	$	7,987	$	—	$	7,987
Interest rate derivative instruments	—		4,458		—		4,458
Total liabilities measured at fair value	$	—	$	12,445	$	—	$	12,445

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

20

	Fair Value Measurements at December 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs  (Level 3)		Balance at December 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

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

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

	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at March 31, 2014	$	2,105,832	$	2,186,839
Long-term debt at March 31, 2013	$	1,789,663	$	1,925,859
Long-term debt at December 31, 2013	$	1,854,563	$	1,912,590

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

Note 14 - Long-term debt

Centennial entered into a two year $125.0 million term loan agreement with a variable interest rate on March 31, 2014. In addition, borrowings outstanding that were classified as long-term debt under the Company’s and Centennial’s commercial paper programs totaled $283.5 million at March 31, 2014, compared to $153.9 million at December 31, 2013, respectively.

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Note 15 - Equity

A summary of the changes in equity was as follows:

Three Months Ended March 31, 2014	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2013	$	2,823,164		$	32,738		$	2,855,902
Net income (loss)	56,662			(523		)	56,139
Other comprehensive income	667			—			667
Dividends declared on preferred stocks	(171		)	—			(171		)
Dividends declared on common stock	(33,809		)	—			(33,809		)
Stock-based compensation	1,336			—			1,336
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	(5,564		)	—			(5,564		)
Net tax benefit on stock-based compensation	4,729			—			4,729
Issuance of common stock	54,574			—			54,574
Contribution from noncontrolling interest	—			16,001			16,001
Balance at March 31, 2014	$	2,901,588		$	48,216		$	2,949,804

Three Months Ended March 31, 2013	Total Stockholders' Equity			Noncontrolling Interest		Total Equity
	(In thousands)
Balance at December 31, 2012	$	2,648,248		$	—	$	2,648,248
Net income	56,515			—		56,515
Other comprehensive loss	(7,894		)	—		(7,894		)
Dividends declared on preferred stocks	(171		)	—		(171		)
Dividends declared on common stock	(32,573		)	—		(32,573		)
Stock-based compensation	1,176			—		1,176
Net tax deficit on stock-based compensation	(1,419		)	—		(1,419		)
Contribution from noncontrolling interest	—			11,100		11,100
Balance at March 31, 2013	$	2,663,882		$	11,100	$	2,674,982

Note 16 - Business segment data

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

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

The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment is constructing Dakota Prairie Refinery in conjunction with Calumet to refine crude oil and 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/Gulf States regions of the United States.

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

22

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, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' 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 2013 Annual Report. Information on the Company's businesses was as follows:

Three Months Ended March 31, 2014	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	73,647	$	—		$	11,033
Natural gas distribution	374,233		—			27,263
Pipeline and energy services	43,661		18,276			4,349
	491,541		18,276			42,645
Exploration and production	116,669		20,867			20,939
Construction materials and contracting	164,423		4,017			(23,574		)
Construction services	269,892		3,738			16,568
Other	328		1,724			264
	551,312		30,346			14,197
Intersegment eliminations	—		(48,622		)	(351		)
Total	$	1,042,853	$	—		$	56,491

Three Months Ended March 31, 2013	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	64,654	$	—		$	9,825
Natural gas distribution	331,754		—			32,518
Pipeline and energy services	27,716		18,718			2,330
	424,124		18,718			44,673
Exploration and production	115,363		9,812			20,284
Construction materials and contracting	161,977		4,294			(20,582		)
Construction services	229,806		1,574			11,664
Other	334		1,818			305
	507,480		17,498			11,671
Intersegment eliminations	—		(36,216		)	—
Total	$	931,604	$	—		$	56,344

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.

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Note 17 - 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 March 31,	2014			2013			2014			2013
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	33		$	40		$	379		$	504
Interest cost	4,440			4,018			858			940
Expected return on assets	(5,125		)	(5,083		)	(1,067		)	(1,107		)
Amortization of prior service cost (credit)	18			18			(348		)	(364		)
Amortization of net actuarial loss	1,313			1,864			318			671
Net periodic benefit cost, including amount capitalized	679			857			140			644
Less amount capitalized	95			110			29			29
Net periodic benefit cost	$	584		$	747		$	111		$	615

In addition to the qualified plan defined pension benefits reflected in the table, the Company has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three months ended March 31, 2014 and 2013, was $1.7 million and $1.9 million, respectively.

Note 18 - Regulatory matters and revenues subject to refund

On April 8, 2014, Montana-Dakota submitted a request to the NDPSC to update the environmental cost recovery rider to reflect actual costs incurred through February 2014 and projected costs through June 2015 related to the recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. If approved, the rates would be effective with service rendered on and after July 1, 2014.

On September 18, 2013, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $6.8 million annually or approximately 6.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. An interim increase of $4.3 million annually or approximately 4.0 percent went into effect for service rendered on or after November 17, 2013. On December 30, 2013, the NDPSC approved a settlement agreement for an increase in the same amount as the interim increase. A hearing on the rate design portion of the case was held February 5, 2014. The NDPSC voted to approve an order approving the allocation of the revenue increase to each rate class and the rate design on April 9, 2014. Final rates were implemented May 1, 2014.

On February 27, 2014, Montana-Dakota filed an application with the NDPSC for approval of an electric generation resource recovery rider for recovery of Montana-Dakota's investment in the 88-megawatt simple-cycle natural gas turbine and associated facilities currently under construction near Mandan, ND. Montana-Dakota requested recovery of $7.4 million annually or approximately 4.6 percent above current rates. Advance determination of prudence and a certificate of public convenience and necessity were received from the NDPSC on April 11, 2012. On March 12, 2014, the NDPSC suspended the filing pending further review. The NDPSC has scheduled a hearing for this matter on May 28, 2014.

On October 31, 2013, WBI Energy Transmission filed a general natural gas rate change application with the FERC for an increase of $28.9 million annually to cover increased investments of $312 million, increased operating costs, and the effect of lower storage and off system volumes. On April 30, 2014, WBI Energy Transmission reached a settlement in principle with FERC Trial Staff and all active parties to resolve the rate case. WBI Energy Transmission intends to file the settlement rates to take effect on an interim basis, effective May 1, 2014, pending final approval of the settlement. The settlement, if approved, will result in final rates which are lower than the rates which were originally requested in the rate case application.

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Note 19 - Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. The Company had accrued liabilities of $31.4 million, $33.3 million and $29.5 million for contingencies, including litigation, production taxes, royalty claims and environmental matters, as of March 31, 2014 and 2013, and December 31, 2013, respectively, which include 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 seeking compensatory damages of $149.7 million. 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. CEM filed a petition with the New York Supreme Court to vacate the arbitration award in favor of LPP. On October 19, 2012, Centennial moved to intervene in the New York Supreme Court action to vacate the arbitration award and also filed a complaint with the New York Supreme Court seeking a declaration that LPP is not entitled to indemnification from Centennial under the guaranty for the arbitration award. The New York Supreme Court granted CEM's petition to vacate the arbitration award on November 20, 2012, and entered an order and judgment to that effect on June 5, 2013. LPP appealed the order and judgment and on February 20, 2014, the New York Supreme Court Appellate Division ruled the arbitration award was properly vacated. LPP filed a motion with the New York Court of Appeals for leave to appeal the decision of the New York Supreme Court Appellate Division. The motion remains pending. Due to the vacation of the arbitration award, the Company no longer believes the loss related to this matter to be probable and thus the liability that was previously recorded in 2011 was reversed in the fourth quarter of 2012. The effect of this was recorded in discontinued operations on the Consolidated Statement of Income. For more information regarding discontinued operations, see Note 9.

Construction MaterialsUntil 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. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

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

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

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

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

Environmental matters

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

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

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

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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 $1.7 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received an order reauthorizing the deferred accounting for the 12 months starting November 30, 2013.

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 of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $12.8 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

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

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

Guarantees

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

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at March 31, 2014, expire in the years ranging from 2014 to 2015; however, Fidelity continues to enter into additional derivative instruments and, as a result, WBI Holdings from time to

27

time may issue additional guarantees on these derivative instruments. The amount outstanding by Fidelity was $7.7 million and was reflected on the Consolidated Balance Sheet at March 31, 2014. 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 March 31, 2014, the fixed maximum amounts guaranteed under these agreements aggregated $48.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $26.8 million in 2014; $2.1 million in 2015; $700,000 in 2016; $600,000 in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at March 31, 2014. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At March 31, 2014, the fixed maximum amounts guaranteed under these letters of credit, aggregated $36.3 million. In 2014 and 2015, $7.0 million and $29.3 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at March 31, 2014.

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 March 31, 2014, the fixed maximum amount guaranteed under this agreement was $4.0 million and is scheduled to expire in 2016. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $700,000. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at March 31, 2014, 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 March 31, 2014.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of March 31, 2014, approximately $588.8 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

Variable interest entities

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

Dakota Prairie Refining, LLCOn February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are expected to be shared equally between WBI Energy and Calumet. The total project cost is currently estimated at $350 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75.0 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

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

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

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	22,996	$	10,793	$	4,774
Other current assets	1,135		—		26
Total current assets	24,131		10,793		4,800
Net property, plant and equipment	207,260		27,356		172,073
Total assets	$	231,391	$	38,149	$	176,873
LIABILITIES
Current liabilities:
Long-term debt due within one year	$	3,000	$	—	$	3,000
Accounts payable	16,103		10,948		8,904
Taxes payable	113		—		5
Accrued compensation	164		—		26
Other accrued liabilities	580		—		461
Total current liabilities	19,960		10,948		12,396
Long-term debt	72,000		—		72,000
Total liabilities	$	91,960	$	10,948	$	84,396

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

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

At March 31, 2014, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, at March 31, 2014, was $8.2 million.

Note 20 - Subsequent Events

Centennial entered into a two year $125.0 million term loan agreement with a variable interest rate on April 2, 2014.

The Company entered into a $150.0 million note purchase agreement on January 28, 2014. On April 15, 2014, the Company issued $50.0 million of Senior Notes with a due date of April 15, 2044, at an interest rate of 5.2 percent. The remaining $100.0 million of Senior Notes under the agreement will be issued on July 15, 2014, with due dates ranging from July 2024 to July 2026 at a weighted average interest rate of 4.3 percent.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION 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 16.

Key Strategies and Challenges

Electric and Natural Gas Distribution

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

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

Pipeline and Energy Services

Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, investments in and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing/refining activities; and expansion of related energy services.

ChallengesChallenges 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 natural gas commodity mix to

30

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; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.

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

Construction Services

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

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

For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2013 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.

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Earnings Overview

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

	Three Months Ended
	March 31,
	2014			2013
	(Dollars in millions, where applicable)
Electric	$	11.0		$	9.8
Natural gas distribution	27.3			32.5
Pipeline and energy services	4.3			2.3
Exploration and production	20.9			20.3
Construction materials and contracting	(23.6		)	(20.6		)
Construction services	16.6			11.7
Other	.3			.4
Intersegment eliminations	(.3		)	—
Earnings before discontinued operations	56.5			56.4
Loss from discontinued operations, net of tax	—			(.1		)
Earnings on common stock	$	56.5		$	56.3
Earnings per common share – basic:
Earnings before discontinued operations	$	.30		$	.30
Discontinued operations, net of tax	—			—
Earnings per common share – basic	$	.30		$	.30
Earnings per common share – diluted:
Earnings before discontinued operations	$	.30		$	.30
Discontinued operations, net of tax	—			—
Earnings per common share – diluted	$	.30		$	.30

Three Months Ended March 31, 2014 and 2013 Consolidated earnings for the quarter ended March 31, 2014, increased$200,000 from the comparable prior period largely due to:

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

• Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, primarily due to higher volumes and prices, at the pipeline and energy services business

• Higher retail sales margins, largely the result of increased retail sales volumes of 10 percent and higher average realized rates, offset in part by higher operation and maintenance expense at the electric business

Partially offsetting these increases were:

• Higher operation and maintenance expense, largely related to higher payroll and benefit-related costs, and the absence in 2014 of the gain on the sale of Montana-Dakota's nonregulated appliance service and repair business in March 2013, offset in part by higher retail sales margins, largely resulting from higher average realized rates at the natural gas distribution business

• Lower earnings resulting from lower construction revenues and margins at the construction materials and contracting business

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FINANCIAL AND OPERATING DATA

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

Electric

	Three Months Ended
	March 31,
	2014		2013
	(Dollars in millions, where applicable)
Operating revenues	$	73.7	$	64.6
Operating expenses:
Fuel and purchased power	26.6		21.6
Operation and maintenance	18.4		16.4
Depreciation, depletion and amortization	8.5		8.6
Taxes, other than income	2.9		2.9
	56.4		49.5
Operating income	17.3		15.1
Earnings	$	11.0	$	9.8
Retail sales (million kWh)	928.9		842.6
Average cost of fuel and purchased power per kWh	$	.027	$	.024

Three Months Ended March 31, 2014 and 2013 Electric earnings increased$1.2 million (12 percent) due to higher retail sales margins, largely the result of increased retail sales volumes of 10 percent and higher average realized rates. Partially offsetting this increase was higher operation and maintenance expense, which includes $1.4 million (after tax) largely related to higher benefit-related costs and higher contract services.

Natural Gas Distribution

	Three Months Ended
	March 31,
	2014			2013
	(Dollars in millions, where applicable)
Operating revenues	$	374.2		$	331.7
Operating expenses:
Purchased natural gas sold	257.3			213.4
Operation and maintenance	37.9			34.1
Depreciation, depletion and amortization	13.3			12.2
Taxes, other than income	17.8			16.3
	326.3			276.0
Operating income	47.9			55.7
Earnings	$	27.3		$	32.5
Volumes (MMdk):
Sales	45.3			44.9
Transportation	39.3			38.2
Total throughput	84.6			83.1
Degree days (% of normal)*
Montana-Dakota/Great Plains	107		%	98		%
Cascade	100		%	99		%
Intermountain	96		%	114		%
Average cost of natural gas, including transportation, per dk	$	5.68		$	4.75
* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended March 31, 2014 and 2013 Natural gas distribution earnings decreased$5.2 million (16 percent) due to:

• Higher operation and maintenance expense, which includes $3.2 million (after tax) largely related to higher payroll and benefit-related costs

33

• The absence in 2014 of the $2.9 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business in March 2013

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

Partially offsetting these decreases were higher retail sales margins, largely resulting from approved rate increases effective in late 2013.

Pipeline and Energy Services

	Three Months Ended
	March 31,
	2014			2013
	(Dollars in millions)
Operating revenues	$	61.9		$	46.4
Operating expenses:
Purchased natural gas sold	26.2			12.8
Operation and maintenance	16.8			17.2
Depreciation, depletion and amortization	7.1			7.2
Taxes, other than income	3.1			3.4
	53.2			40.6
Operating income	8.7			5.8
Earnings	$	4.3		$	2.3
Transportation volumes (MMdk)	52.5			36.8
Natural gas gathering volumes (MMdk)	9.5			9.9
Customer natural gas storage balance (MMdk):
Beginning of period	26.7			43.7
Net withdrawal	(16.3		)	(19.0		)
End of period	10.4			24.7

Three Months Ended March 31, 2014 and 2013 Pipeline and energy services earnings increased$2.0 million (87 percent) due to:

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

• Higher earnings of $600,000 (after tax) due to increased transportation volumes

These increases were partially offset by lower storage services revenue of $600,000 (after tax), largely due to lower average storage balances.

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

34

Exploration and Production

	Three Months Ended
	March 31,
	2014			2013
	(Dollars in millions, where applicable)
Operating revenues:
Oil	$	113.6		$	100.0
NGL	6.9			7.5
Natural gas	30.5			19.2
Realized gain (loss) on commodity derivatives	(6.8		)	4.3
Unrealized loss on commodity derivatives	(6.7		)	(5.8		)
	137.5			125.2
Operating expenses:
Operation and maintenance:
Lease operating costs	24.2			20.8
Gathering and transportation	2.3			4.3
Other	11.8			10.2
Depreciation, depletion and amortization	49.5			43.1
Taxes, other than income:
Production and property taxes	13.0			11.6
Other	.4			.3
	101.2			90.3
Operating income	36.3			34.9
Earnings	$	20.9		$	20.3
Production:
Oil (MBbls)	1,280			1,118
NGL (MBbls)	164			201
Natural gas (MMcf)	5,278			6,713
Total production (MBOE)	2,324			2,438
Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
Oil (per Bbl)	$	88.74		$	89.44
NGL (per Bbl)	$	42.26		$	37.33
Natural gas (per Mcf)	$	5.77		$	2.86
Average realized prices (including realized gain/loss on commodity derivatives):
Oil (per Bbl)	$	85.75		$	91.87
NGL (per Bbl)	$	42.26		$	37.33
Natural gas (per Mcf)	$	5.21		$	3.10
Average depreciation, depletion and amortization rate, per BOE	$	20.45		$	16.90
Production costs, including taxes, per BOE:
Lease operating costs	$	10.39		$	8.54
Gathering and transportation	1.01			1.76
Production and property taxes	5.58			4.74
	$	16.98		$	15.04

Three Months Ended March 31, 2014 and 2013 Exploration and production earnings increased$600,000 (3 percent) due to:

• Higher average realized natural gas prices of 102 percent, excluding gain/loss on commodity derivatives

• Increased oil production of 14 percent, primarily related to drilling activity in the Paradox Basin

• Lower gathering and transportation expenses of $1.2 million (after tax)

Partially offsetting these increases were:

• A loss of $7.0 million (after tax) resulting from a realized commodity derivative loss in 2014 compared to a realized commodity derivative gain in 2013

• Decreased natural gas production of 21 percent, largely due to the sale of non-strategic assets

35

• Higher depreciation, depletion and amortization expense of $4.0 million (after tax), primarily due to higher depletion rates

• Higher lease operating and general and administrative expenses of $3.2 million (after tax)

• Higher production taxes of $1.3 million (after tax), primarily resulting from higher revenues

• Decreased NGL production of 18 percent

Construction Materials and Contracting

	Three Months Ended
	March 31,
	2014			2013
	(Dollars in millions)
Operating revenues	$	168.5		$	166.3
Operating expenses:
Operation and maintenance	175.8			166.6
Depreciation, depletion and amortization	17.6			19.0
Taxes, other than income	8.3			8.5
	201.7			194.1
Operating loss	(33.2		)	(27.8		)
Loss	$	(23.6	)	$	(20.6	)
Sales (000's):
Aggregates (tons)	2,829			2,958
Asphalt (tons)	184			149
Ready-mixed concrete (cubic yards)	497			480

Three Months Ended March 31, 2014 and 2013 Construction materials and contracting experienced a seasonal first quarter loss of $23.6 million compared to a loss of $20.6 million a year ago (15 percent increased loss). The increased seasonal loss was the result of:

• Lower earnings of $3.1 million (after tax) resulting from lower construction revenues and margins

• Higher selling, general and administrative expenses of $1.7 million (after tax), including higher insurance costs

Partially offsetting the increased loss were higher earnings resulting from higher other product line margins.

Construction Services

	Three Months Ended
	March 31,
	2014		2013
	(In millions)
Operating revenues	$	273.6	$	231.4
Operating expenses:
Operation and maintenance	234.0		198.4
Depreciation, depletion and amortization	3.2		3.0
Taxes, other than income	10.2		9.6
	247.4		211.0
Operating income	26.2		20.4
Earnings	$	16.6	$	11.7

Three Months Ended March 31, 2014 and 2013 Construction services earnings increased$4.9 million (42 percent), primarily due to higher workloads and margins in the Western region.

36

Other

	Three Months Ended
	March 31,
	2014		2013
	(In millions)
Operating revenues	$	2.1	$	2.2
Operating expenses:
Operation and maintenance	1.2		1.3
Depreciation, depletion and amortization	.6		.5
	1.8		1.8
Operating income	.3		.4
Income from continuing operations	.3		.4
Loss from discontinued operations, net of tax	—		(.1		)
Earnings	$	.3	$	.3

Intersegment Transactions

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

	Three Months Ended
	March 31,
	2014		2013
	(In millions)
Intersegment transactions:
Operating revenues	$	48.6	$	36.2
Purchased natural gas sold	38.6		27.0
Operation and maintenance	9.2		9.2
Depreciation, depletion and amortization	.2		—
Earnings on common stock	.3		—

For more information on intersegment eliminations, see Note 16.

PROSPECTIVE INFORMATION

The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain of the Company's businesses. Many of these highlighted points are "forward-looking statements." There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Part II, Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2013 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.

MDU Resources Group, Inc.

• Adjusted earnings per common share for 2014, diluted, are projected in the range of $1.50 to $1.65, excluding discontinued operations and the unrealized loss of $4.3 million (after tax) on commodity derivatives. Including these adjustments, GAAP earnings guidance for 2014 is in the same range. Unrealized commodity derivatives fair values can fluctuate causing actual GAAP earnings to vary accordingly.

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

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

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

37

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

• Estimated gross capital expenditures for 2014 are approximately $1.2 billion, an increase from prior guidance with the inclusion of the Powder River Basin first quarter 2014 acquisition and associated drilling capital costs. The estimate excludes noncontrolling interest capital expenditures related to Dakota Prairie Refining.

Electric and natural gas distribution

• Rate base growth is projected to be approximately 9 percent compounded annually over the next five years, including plans for an approximate $1.3 billion capital investment program.

• Regulatory actions

◦ The Company filed an application February 27, 2014, with the NDPSC requesting approval for a generation resource recovery rider to recover costs associated with the 88-MW simple-cycle natural gas turbine and associated facilities currently under construction, as discussed in Note 18.

◦ The Company filed an application September 18, 2013, with the NDPSC for a natural gas rate increase, as discussed in Note 18.

◦ The Company filed an application in February 2013 with the NDPSC for approval of an environmental cost recovery rider related to ongoing construction costs at the Big Stone Station for the installation of the BART air-quality control system. The Company's share of the cost for the installation is now estimated at approximately $90 million, down from the earlier estimate of $100 million, and is expected to be complete in 2015. The NDPSC approved the Company’s request for the environmental cost recovery rider and rates were implemented effective January 15, 2014. On April 8, 2014, the Company requested an update to the rider for actual costs through February 2014 and projected costs through June 2015 to be effective July 1, 2014. The NDPSC had earlier approved advance determination of prudence for recovery of costs on the system. For more information, see Note 18.

• Investments are being made in 2014 totaling approximately $70 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is substantially higher than the national average.

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

• The Company, along with a partner expects to build a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The Company’s share of the cost is estimated at approximately $170 million. The project is a MISO multi-value project. A route application was filed in August 2013 with the state of South Dakota, and in October 2013 with the state of North Dakota. A route permit hearing was held in North Dakota on April 1, 2014. A route permit hearing is scheduled in South Dakota on June 10, 2014. The project is expected to be complete in 2019.

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

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

Pipeline and energy services

• The Company, in conjunction with Calumet, formed Dakota Prairie Refining, to develop, build and operate Dakota Prairie Refinery. Construction began on the facility in late March 2013 and, when complete, it will process Bakken crude into diesel, which will be marketed within the Bakken region. Other by-products, naphtha and atmospheric tower bottoms, will be railed to other areas. The total project cost estimate is approximately $350 million, with a projected in-service date in late 2014. EBITDA for the first year of operation is projected to be in the range of $70 million to $90 million, to be shared equally with Calumet.

• In January 2014, the Company launched an open season to obtain capacity commitments on a proposed 375-mile natural gas pipeline from western North Dakota to northwestern Minnesota to transport natural gas to markets in eastern North Dakota,

38

Minnesota, Wisconsin, Michigan and other Midwest markets. The pipeline is expected to provide access to additional markets via interconnections with pipelines owned by Great Lakes Gas Transmission, Viking Gas Transmission and potentially TransCanada, in northwestern Minnesota. An interconnection with the Alliance Pipeline system in eastern North Dakota also is possible. Initially the pipeline would transport approximately 400 MMcf per day of natural gas and could be expanded to more than 500 MMcf per day. The project investment is estimated to be approximately $650 million. Following the open season and receipt of adequate capacity commitments and necessary permits and regulatory approvals, construction on the new pipeline could begin in 2016 with completion expected in 2017.

• On October 31, 2013, WBI Energy Transmission filed a Section 4 rate case with the FERC, as discussed in Note 18.

• The Company is engaged in various natural gas pipeline projects to be constructed in 2014, including connections for the planned Garden Creek II natural gas processing plant in the Bakken, an expansion of its transmission system to increase capacity to the Black Hills, and a 24-mile pipeline and related processing facilities to transport Fidelity's Paradox basin natural gas production. The total cost for these projects is approximately $50 million.

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

Exploration and production

• The Company expects to spend approximately $670 million in capital expenditures in 2014, which is likely to be partially offset by planned asset sales later this year.

• For 2014, the Company expects a 15 to 20 percent increase in oil production. NGL production is expected to decline 20 to 25 percent and natural gas production is expected to be 25 to 30 percent lower compared to a year ago. The declines are primarily the result of the divestment of certain non-strategic natural gas-based properties in 2013 and the expected divestment of the Company's south Texas assets this year. The vast majority of the capital program is focused on growing oil production.

• The Company has a total of four operated drilling rigs deployed on its acreage in the Bakken and Paradox areas, with two rigs in each area.

• Bakken areas

◦ The Company owns a total of approximately 121,000 net acres of leaseholds in Mountrail and Stark counties, North Dakota and Richland County, Montana. The Middle Bakken and Three Forks formations are targeted in North Dakota and the Red River formation is targeted in Montana.

◦ Capital expenditures are expected to total approximately $130 million in 2014.

◦ Net oil production for the first quarter 2014 was approximately 7,600 BOPD which is a 300 BOPD increase from the same 2013 period.

◦ Alternative completion techniques, including increased stage count and cemented liners in the Middle Bakken (Mountrail County) and Three Forks (Mountrail and Stark counties) are being tested, with completion design changes to be finalized later in 2014.

• Paradox Basin, Utah

◦ The Company owns approximately 130,000 net acres of leaseholds including its acquisition of 35,000 net acres of leaseholds in February 2014 and has an option to earn another 20,000 acres. The Company expects to further expand its acreage in the basin.

◦ Capital expenditures are expected to total approximately $180 million in 2014.

◦ Well costs range from $9 million to $12 million per well depending upon lateral lengths. With longer lateral lengths, estimated ultimate recoveries are expected to increase with the upper range now at 1.5 MMBbls of oil per well.

39

◦ The CCU 12-1 well continues to exceed expectations with the well still flowing over 1,000 BOPD gross. It is anticipated that artificial lift facilities will be installed in the near future. Cumulative production is 690 MBbls of oil.

◦ Net oil production for first quarter 2014 was approximately 3,575 BOPD, up 121 percent from first quarter 2013 and 22 percent higher than fourth quarter 2013. Current production is approximately 3,900 BOPD.

◦ The Company's understanding of this play and the quality of the play continues to improve. It is anticipated that this field will play a key role in the Company's oil growth strategy.

• Powder River Basin, Wyoming

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

◦ Capital expenditures are expected to total approximately $270 million in 2014 including the acquisition costs, related closing adjustments and drilling capital.

◦ At the end of March 2014, average net production was 1,630 BOE per day.

• Earnings guidance reflects estimated average NYMEX index prices for May through December 2014 in the range of $96 to $102 per Bbl of crude oil, and $4.25 to $4.75 per Mcf of natural gas. Estimated prices for NGLs are in the range of $37 to $40 per Bbl.

• Derivatives:

◦ For April through June 2014, the Company has derivative instruments for 11,000 BOPD, July through September 2014 for 12,000 BOPD and 7,000 BOPD for October through December 2014, with a weighted average price of $95.11.

◦ For April through December 2014, the Company has derivative instruments for 40,000 MMBtu of natural gas per day at a weighted average price of $4.10.

◦ For 2015, the Company has a derivative instrument for 10,000 MMBtu of natural gas per day at $4.28.

◦ The commodity derivative instruments that are in place as of April 30, 2014, are summarized in the following chart:

40

Commodity	Type	Index	Period Outstanding	Forward Notional Volume (Bbl/MMBtu)	Price (Per Bbl/MMBtu)
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$95.15
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$95.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$90.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$91.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$92.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$93.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$98.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$99.00
Crude Oil	Swap	NYMEX	4/14 - 6/14	91,000	$100.07
Crude Oil	Swap	NYMEX	4/14 - 12/14	275,000	$94.05
Crude Oil	Swap	NYMEX	4/14 - 12/14	275,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 9/14	184,000	$95.75
Crude Oil	Swap	NYMEX	7/14 - 9/14	184,000	$96.00
Crude Oil	Swap	NYMEX	7/14 - 9/14	92,000	$96.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$94.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	368,000	$96.00
Natural Gas	Swap	NYMEX	4/14 - 12/14	5,500,000	$4.13
Natural Gas	Swap	NYMEX	4/14 - 12/14	2,750,000	$4.05
Natural Gas	Swap	NYMEX	4/14 - 12/14	2,750,000	$4.10
Natural Gas	Swap	NYMEX	1/15 - 12/15	3,650,000	$4.28

Construction materials and contracting

• Approximate work backlog as of March 31, 2014, was $653 million, compared to $589 million a year ago. Private work represents 9 percent of construction backlog and public work represents 91 percent of backlog. Bidding opportunities are good and additional backlog has been secured since March 31, 2014. The backlog includes a variety of projects such as highway grading, paving and underground projects, airports, bridge work, reclamation and harbor expansions.

• The Company's approximate backlog in North Dakota as of March 31, 2014, was $118 million. North Dakota backlog was $67 million a year ago.

• Projected revenues included in the Company's 2014 earnings guidance are in the range of $1.6 billion to $1.8 billion.

• The Company anticipates margins in 2014 to be in line with 2013 margins.

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

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

• Of the seven labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the 2013 Annual Report, four have been ratified. The three remaining contracts are still in negotiations.

Construction services

• Approximate work backlog as of March 31, 2014, was $397 million, compared to $465 million a year ago. Bidding opportunities are good and additional backlog has been secured since March 31, 2014. The backlog includes a variety of

41

projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.

• The Company's approximate backlog in North Dakota as of March 31, 2014, was $7 million. The construction services business did not have any backlog in North Dakota a year ago.

• Projected revenues included in the Company's 2014 earnings guidance are in the range of $1.0 billion to $1.1 billion.

• The Company anticipates lower margins in 2014 compared to 2013 margins.

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

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

The Company's critical accounting policies involving significant estimates include impairment testing of oil and natural gas properties, impairment testing of long-lived assets and intangibles, revenue recognition, pension and other postretirement benefits, and income taxes. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 2013 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2013 Annual Report.

LIQUIDITY AND CAPITAL COMMITMENTS

At March 31, 2014, the Company had cash and cash equivalents of $83.7 million and available capacity of $454.3 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year from various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.

Cash flows

Operating activitiesThe changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.

Cash flows provided by operating activities in the first three months of 2014 increased$163,000 from the comparable period in 2013. Lower working capital and other changes combined with higher operating cash flows at the construction services and pipeline and energy services businesses, were largely offset by lower operating cash flows at the construction materials and contracting, natural gas distribution and exploration and production businesses.

Investing activities Cash flows used in investing activities in the first three months of 2014increased$209.5 million from the comparable period in 2013. The increase in cash flows used in investing activities was primarily due to higher acquisition-related capital expenditures at the exploration and production business.

Financing activities Cash flows provided by financing activities in the first three months of 2014increased$222.7 million from the comparable period in 2013. The increase in cash flows provided by financing activities was primarily due to higher issuance of long-term debt of $197.5 million, primarily at the exploration and production business; as well as the issuance of $54.8 million of common stock. Partially offsetting this increase were higher dividends paid in 2014 compared to 2013 due to the acceleration of the first quarter 2013 quarterly common stock dividend to 2012.

Defined benefit pension plans

There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the 2013 Annual Report. For more information, see Note 17 and Part II, Item 7 in the 2013 Annual Report.

Capital expenditures

Net capital expenditures for the first three months of 2014 were $365.6 million and are estimated to be approximately $1.1 billion for 2014. Estimated capital expenditures include:

• System upgrades

• Routine replacements

• Service extensions

• Routine equipment maintenance and replacements

• Buildings, land and building improvements

42

• Pipeline, gathering and other midstream projects

• Further development of existing properties, acquisition of additional leasehold acreage, exploratory drilling and proceeds from the sale of non-strategic assets at the exploration and production segment

• Power generation and transmission opportunities, including certain costs for additional electric generating capacity

• Environmental upgrades

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

• Other growth opportunities

The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2014 capital expenditures referred to previously. The Company expects the 2014 estimated capital expenditures to be funded by various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.

Capital resources

Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at March 31, 2014. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. For more information on the covenants, certain other conditions and cross-default provisions, see Part II, Item 8 - Note 9, in the 2013 Annual Report.

The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at March 31, 2014:

Company	Facility		Facility Limit			Amount Outstanding			Letters of Credit			Expiration Date
			(In millions)
MDU Resources Group, Inc.	Commercial paper/ Revolving credit agreement	(a)	$	125.0		$	54.0	(b)	$	—		10/4/17
Cascade Natural Gas Corporation	Revolving credit agreement		$	50.0	(c)	$	—		$	2.2	(d)	7/9/18
Intermountain Gas Company	Revolving credit agreement		$	65.0	(e)	$	—		$	—		7/13/18
Centennial Energy Holdings, Inc.	Commercial paper/ Revolving credit agreement	(f)	$	500.0		$	229.5	(b)	$	—		6/8/17
(a) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement. (b) Amount outstanding under commercial paper program. (c) Certain provisions allow for increased borrowings, up to a maximum of $75 million. (d) The outstanding letter of credit, as discussed in Note 19, reduces the amount available under the credit agreement. (e) Certain provisions allow for increased borrowings, up to a maximum of $90 million. (f) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $650 million). There were no amounts outstanding under the credit agreement.

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

The following includes information related to the preceding table.

MDU Resources Group, Inc. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term

43

basis through continued commercial paper borrowings. The Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in the Company's credit ratings have not limited, nor are currently expected to limit, the Company's ability to access the capital markets. If the Company were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.

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

The Company's coverage of fixed charges including preferred stock dividends was 4.8 times for the 12 months ended March 31, 2014 and December 31, 2013. Due to the $246.8 million after-tax noncash write-downs of oil and natural gas properties in 2012, earnings were insufficient by $17.2 million to cover fixed charges for the 12 months ended March 31, 2013. If the $246.8 million after-tax noncash write-downs were excluded, the coverage of fixed charges including preferred stock dividends would have been 4.6 times for the 12 months ended March 31, 2013.

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

Total equity as a percent of total capitalization was 58 percent, 59 percent and 60 percent at March 31, 2014 and 2013 and December 31, 2013, respectively. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus total equity. This ratio indicates how a company is financing its operations, as well as its financial strength.

On May 20, 2013, the Company entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 7.5 million shares of the Company's common stock. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement. Sales of such common stock may not be made after February 28, 2016. Proceeds from the shares of common stock under the agreement have been and are expected to be used for corporate development purposes and other general corporate purposes. The Company issued 1.5 million shares of stock during the first quarter of 2014 under the Equity Distribution Agreement, receiving net proceeds of $50.1 million.

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

The Company entered into a $150.0 million note purchase agreement on January 28, 2014. On April 15, 2014, the Company issued $50.0 million of Senior Notes with a due date of April 15, 2044, at an interest rate of 5.2 percent. The remaining $100.0 million of Senior Notes under the agreement will be issued on July 15, 2014, with due dates ranging from July 2024 to July 2026 at a weighted average interest rate of 4.3 percent.

MDU Energy Capital, LLC On December 12, 2013, MDU Energy Capital entered into a $30.0 million note purchase agreement. MDU Energy Capital issued the Senior Notes under the agreement on January 27, 2014, with due dates ranging from January 2029 to January 2044 at a weighted average interest rate of 5.3 percent.

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

44

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

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

WBI Energy Transmission, Inc. WBI Energy Transmission has a $175.0 million amended and restated uncommitted long-term private shelf agreement with an expiration date of September 12, 2016. WBI Energy Transmission had $100.0 million of notes outstanding at March 31, 2014, which reduced capacity under this uncommitted private shelf agreement.

Off balance sheet arrangements

In connection with the sale of the Brazilian Transmission Lines, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines. For more information, see Note 10.

Centennial continues to guarantee CEM's obligations under a construction contract for an electric generating facility near Hobbs, New Mexico. For more information, see Note 19.

Contractual obligations and commercial commitments

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

The Company's contractual obligations relating to long-term debt at March 31, 2014, increased $251.3 million or 14 percent from December 31, 2013. As of March 31, 2014, the Company's contractual obligations related to long-term debt aggregated $2,105.8 million. The scheduled amounts of redemption (for the twelve months ended March 31, of each year listed) aggregate $12.2 million in 2015; $534.3 million in 2016; $154.9 million in 2017; $334.5 million in 2018; $126.8 million in 2019; and $943.1 million thereafter.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2013 Annual Report, the Consolidated Statements of Comprehensive Income and Notes 7 and 12.

Commodity price risk

Fidelity utilizes derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on forecasted sales of oil and natural gas production.

The following table summarizes derivative agreements entered into by Fidelity as of March 31, 2014. These agreements call for Fidelity to receive fixed prices and pay variable prices.

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	(Forward notional volume and fair value in thousands)
		Weighted Average Fixed Price (Per Bbl/MMBtu)		Forward Notional Volume (Bbl/MMBtu)	Fair Value
Oil swap agreements maturing in 2014		$	95.11	2,749	$	(8,229	)
Natural gas swap agreements maturing in 2014		$	4.10	11,000	$	(3,957	)
Natural gas swap agreement maturing in 2015		$	4.28	3,650	$	330

Interest rate risk

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

At March 31, 2014, the Company had no outstanding interest rate hedges.

Foreign currency risk

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

At March 31, 2014, the Company had no outstanding foreign currency hedges.

ITEM 4. CONTROLS AND PROCEDURES

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

Evaluation of disclosure controls and procedures

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

Changes in internal controls

No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended March 31, 2014, that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions.

The Company is including the following factors and cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans,

46

objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these factors and cautionary statements.

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

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

There are no material changes in the Company's risk factors from those reported in Part I, Item 1A - Risk Factors in the 2013 Annual Report other than the risk related to environmental laws and regulations. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

Environmental and Regulatory Risks

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

The Company is subject to environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, cause delays as a result of litigation and administrative proceedings, and create compliance, remediation, containment, monitoring and reporting obligations, particularly with regard to laws relating to electric generation operations and oil and natural gas development and processing. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Although the Company strives to comply with all applicable environmental laws and regulations, public and private entities and private individuals may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations with which they have differing interpretations of the Company's legal or regulatory compliance. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings that may arise.

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

The EPA has issued draft regulations that outline several possible approaches for coal combustion residuals management under the RCRA. One approach, designating coal ash as a hazardous waste, if adopted would significantly change the manner and increase the costs of managing coal ash at five plants that supply electricity to customers of Montana-Dakota. This designation also could significantly increase costs for Knife River, which beneficially uses fly ash as a cement replacement in ready-mixed concrete and road base applications.

In December 2011, the EPA finalized the Mercury and Air Toxics Standards rules that will require reductions in mercury and other air emissions from coal- and oil-fired electric utility steam generating units. Montana-Dakota evaluated the pollution control technologies needed at its electric generation resources to comply with this final rule and determined that additional particulate matter control would be required to control non-mercury metal emissions at the Lewis & Clark Station near Sidney, Montana, and that such control could be accomplished through installation of a baghouse. Montana-Dakota reevaluated its options and determined the baghouse is not currently an economically effective means of compliance. Montana-Dakota now

47

intends to comply with the rule by co-firing the plant with natural gas and lignite. Controls must be in place by April 16, 2015, or April 16, 2016, if a one-year extension is granted for completion of the pollution control project.

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

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table includes information with respect to the Company's purchase of equity securities:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares (or Units) Purchased (1)	(b)  Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
January 1 through January 31, 2014	—
February 1 through February 28, 2014	165,091		$33.70
March 1 through March 31, 2014	—
Total	165,091
(1) Represents shares of common stock withheld by the Company to pay taxes in connection with the vesting of shares granted pursuant to the Long-Term Performance-Based Incentive Plan. (2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 6. EXHIBITS

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

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SIGNATURES

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

		MDU RESOURCES GROUP, INC.
DATE:	May 7, 2014	BY:	/s/ Doran N. Schwartz
			Doran N. Schwartz
			Vice President and Chief Financial Officer
		BY:	/s/ Nathan W. Ring
			Nathan W. Ring
			Vice President, Controller and Chief Accounting Officer

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EXHIBIT INDEX

Exhibit No.
+10(a)	Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 12, 2014
+10(b)	Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated March 13, 2014
10(c)	Purchase and Sale Agreement, dated February 10, 2014, dated effective October 1, 2013, between Fidelity Exploration & Production Company, Fidelity Oil Co. and Ballard Petroleum Holdings LLC
10(d)	Purchase and Sale Agreement, dated February 10, 2014, dated effective October 1, 2013, between Fidelity Exploration & Production Company, Fidelity Oil Co. and Maurice W. Brown Oil & Gas, LLC
12	Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
31(a)	Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b)	Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95	Mine Safety Disclosures
101	The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail

+ Management contract, compensatory plan or arrangement.

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

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EX-10.A

MDU RESOURCES GROUP, INC.

LONG-TERM PERFORMANCE-BASED INCENTIVE PLAN

PERFORMANCE SHARE AWARD AGREEMENT

{ }                        

In accordance with the terms of the MDU Resources Group, Inc. Long-Term Performance-Based Incentive Plan (the "Plan"), pursuant to action of the Compensation Committee of the Board of Directors of MDU Resources Group, Inc. (the "Committee"), MDU Resources Group, Inc. (the "Company") hereby grants to you (the "Participant") Performance Shares (the "Award"), subject to the terms and conditions set forth in this Award Agreement (including Annexes A and B hereto and all documents incorporated herein by reference), as set forth below:

Target Award:	{ } Performance Shares (the "Target Award")
Performance Period:	{ } through { } (the "Performance Period")
Date of Grant:	{ }
Dividend Equivalents:	Yes

THESE PERFORMANCE SHARES ARE SUBJECT TO FORFEITURE AS PROVIDED HEREIN.  THIS AWARD AND AMOUNTS RECEIVED IN CONNECTION WITH THIS AWARD ARE ALSO SUBJECT TO FORFEITURE, RECAPTURE OR OTHER ACTION IN THE EVENT OF AN ACCOUNTING RESTATEMENT, AS PROVIDED IN THE PLAN.

Further terms and conditions of the Award are set forth in Annexes A and B hereto, which are integral parts of this Award Agreement.

All terms, provisions and conditions applicable to the Award set forth in the Plan and not set forth in this Award Agreement are hereby incorporated herein by reference.  To the extent any provision hereof is inconsistent with a provision of the Plan, the provisions of the Plan will govern.  The Participant hereby acknowledges receipt of a copy of this Award Agreement, including Annexes A and B hereto, and a copy of the Plan and agrees to be bound by all the terms and provisions hereof and thereof.

MDU RESOURCES GROUP, INC.
By:
	David L. Goodin
	President and
	Chief Executive Officer

Agreed :

___________________

Participant

ANNEX A

TO

MDU RESOURCES GROUP, INC.

LONG-TERM PERFORMANCE-BASED INCENTIVE PLAN

PERFORMANCE SHARE AWARD AGREEMENT

It is understood and agreed that the Award of Performance Shares evidenced by the Award Agreement to which this is annexed is subject to the following additional terms and conditions.

1.            Nature of Award .  The Target Award represents the opportunity to receive shares of Company common stock, $1.00 par value ("Shares") and Dividend Equivalents on such Shares.  The number of Shares that may be earned under this Award shall be determined pursuant to Section 2 hereof.  The amount of Dividend Equivalents that may be earned under this Award shall be determined pursuant to Section 4 hereof.  Except for Dividend Equivalents, which are paid in cash, Awards will be paid in Shares.

2.            Determination of Number of Shares Earned .

The number of Shares earned, if any, for the Performance Period shall be determined in accordance with the following formula:

#of Shares = Payout Percentage X Target Award

The "Payout Percentage" is based on the Company's total shareholder return ("TSR") relative to that of the Peer Group listed on Annex B (the "Percentile Rank") for the Performance Period, determined in accordance with the following table:

Percentile Rank	Payout Percentage (% of Target Award)
75th or higher	200%
50th	100%
25th	20%
less than 25th	0%

If the Company achieves a Percentile Rank between the 25th and 50th percentiles, the Payout Percentage shall be equal to 20%, plus 3.2% for each Percentile Rank whole percentage above the 25th percentile.  If the Company achieves a Percentile Ranking between the 50th and 75th percentiles, the Payout Percentage shall be equal to 100%, plus 4.0% for each Percentile Rank whole percentage above the 50th percentile. 

If the Company’s TSR for the Performance Period is negative, the number of shares otherwise earned, if any, for the Performance Period will be reduced in accordance with the following table:

TSR	Reduction In Award
0% through -5%	50%
-5.01% through -10%	60%
-10.01% through -15%	70%
-15.01% through -20%	80%
-20.01% through -25%	90%
-25.01% or below	100%

The Percentile Rank of a given company's TSR is defined as the percentage of the Peer Group companies' returns falling at or below the given company's TSR.  The formula for calculating the Percentile Rank follows:

Percentile Rank = (n - r + 1)/n x 100

Where:

n = total number of companies in the Peer Group, including the Company

r = the numeric rank of the Company's TSR relative to the Peer Group, where the highest return in the group is ranked number 1

To illustrate, if the Company's TSR is the third highest in the Peer Group comprised of 23 companies, its Percentile Rank would be 91.  The calculation is: (23 - 3 + 1)/23 x 100 = 91.

The Percentile Rank shall be rounded to the nearest whole percentage.

If the common stock of a company in the Peer Group ceases to be traded during the Performance Period, the company will be deleted from the Peer Group.  Percentile Rank will be calculated without regard to the return of the deleted company.

If the Company or a company in the Peer Group spins off a segment of its business, the shares of the spun-off entity will be treated as a cash dividend that is reinvested in the Company or the company in the Peer Group.

Total shareholder return is the percentage change in the value of an investment in the common stock of a company from the initial investment made on the last trading day in the calendar year preceding the beginning of the performance period through the last trading day in the final year of the performance period.  It is assumed that dividends are reinvested in additional shares of common stock at the frequency paid.

All Performance Shares that are not earned for the Performance Period shall be forfeited. 

3.            Issuance of Shares and Mandatory Holding Period . Subject to any restrictions on distributions of Shares under the Plan, and subject to Section 6 of this Annex A, the Shares earned under the Award, if any, shall be issued to the Participant as soon as practicable (but no later than the next March 10) following the close of the Performance Period.  The Participant shall retain 50% of the net after-tax Shares that are earned under this Award until the earlier of (i) the end of the two-year period commencing on the date any Shares earned under this Award are issued and (ii) the Participant’s termination of employment.

4.            Dividend Equivalents . Dividend Equivalents shall be earned with respect to any Shares issued to the Participant pursuant to this Award.  The amount of Dividend Equivalents earned shall be equal to the total dividends declared on a Share between the Date of Grant of this Award and the last day of the Performance Period, multiplied by the number of Shares issued to the Participant pursuant to the Award Agreement.  Any Dividend Equivalents earned shall be paid in cash to the Participant when the Shares to which they relate are issued or as soon as practicable thereafter, but no later than the next March 10 following the close of the Performance Period.  If the Award is forfeited or if no Shares are issued, no Dividend Equivalents shall be paid.

5.            Termination of Employment .

(a)           If the Participant's employment with the Company is terminated during the Performance Period (1) for "Cause" (as defined below) at any time or (2) for any reason other than "Cause" before the Participant, as of the effective date of termination, has reached age 55 and completed 10 "Years of Service" (as defined below), all Performance Shares (and related Dividend Equivalents) shall be forfeited.

(b)           If the Participant's employment with the Company is terminated for any reason other than "Cause" after the Participant, as of the effective date of termination, has reached age 55 and completed 10 "Years of Service" (1) during the first year of the Performance Period, all Performance Shares (and related Dividend Equivalents) shall be forfeited; (2) during the second year of the Performance Period, determination of the Company's Percentile Rank for the Performance Period will be made by the Committee at the end of the Performance Period, and Shares (and related Dividend Equivalents) earned, if any, will be paid based on the Payout Percentage, prorated for the number of full months elapsed from and including the month in which the Performance Period began to and including the month in which the termination of employment occurs; and (3) during the third year of the Performance Period, determination of the Company's Percentile Rank for the Performance Period will be made by the Committee at the end of the Performance Period, and Shares (and related Dividend Equivalents) earned, if any, will be paid based on the Payout Percentage without prorating.

(c)           For purposes of the Award Agreement, the term "Cause" shall mean the Participant's fraud or dishonesty that has resulted or is likely to result in material economic damage to the Company or a Subsidiary, or the Participant's willful nonfeasance if such nonfeasance is not cured within ten days of written notice from the Company or a Subsidiary, as determined in good faith by a vote of at least two-thirds of the non-employee directors of the Company at a meeting of the Board at which the Participant is provided an opportunity to be heard.  For purposes of the

Award Agreement, the term "Years of Service" shall mean the years a Participant is employed by the Company and/or a Subsidiary.

6.            Tax Withholding . Pursuant to Article 16 of the Plan, the Committee shall have the power and the right to deduct or withhold, or require the Participant to remit to the Company, an amount sufficient to satisfy any Federal, state and local taxes (including the Participant's FICA obligations) required by law to be withheld with respect to the Award.  The Committee may condition the delivery of Shares upon the Participant's satisfaction of such withholding obligations.  The Participant may elect to satisfy all or part of such withholding requirement by tendering previously-owned Shares or by having the Company withhold Shares having a Fair Market Value equal to the minimum statutory withholding that could be imposed on the transaction (based on minimum statutory withholding rates for Federal, state and local tax purposes, as applicable, including payroll taxes, that are applicable to such supplemental taxable income).  Such election shall be irrevocable, made in writing, signed by the Participant, and shall be subject to any restrictions or limitations that the Committee, in its sole discretion, deems appropriate.

7.            Ratification of Actions . By accepting the Award or other benefit under the Plan, the Participant and each person claiming under or through him or her shall be conclusively deemed to have indicated the Participant's acceptance and ratification of, and consent to, any action taken under the Plan or the Award by the Company, its Board of Directors, or the Committee.

8.            Notices . Any notice hereunder to the Company shall be addressed to its office, 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506; Attention: Corporate Secretary, and any notice hereunder to the Participant shall be addressed to him or her at the address specified on the Award Agreement, subject to the right of either party to designate at any time hereafter in writing some other address.

9.            Definitions . Capitalized terms not otherwise defined herein or in the Award Agreement shall have the meanings given them in the Plan.

10.           Governing Law and Severability . To the extent not preempted by Federal law, the Award Agreement will be governed by and construed in accordance with the laws of the State of Delaware, without regard to conflicts of law provisions.  In the event any provision of the Award Agreement shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Award Agreement, and the Award Agreement shall be construed and enforced as if the illegal or invalid provision had not been included.

11.           No Rights to Continued Employment . The Award Agreement is not a contract of employment.  Nothing in the Plan or in the Award Agreement shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate the Participant's employment at any time, for any reason or no reason, or confer upon the Participant the right to continue in the employ of the Company or a Subsidiary.

ANNEX B

TO

MDU RESOURCES GROUP, INC.

LONG-TERM PERFORMANCE-BASED INCENTIVE PLAN

PERFORMANCE SHARE AWARD AGREEMENT

PEER GROUP COMPANIES

ALLETE, Inc.

Alliant Energy Corporation

Atmos Energy

Avista Corporation

Bill Barrett Corporation

Black Hills Corporation

Comstock Resources, Inc.

EMCOR Group Inc.

EQT Corporation

Granite Construction Incorporated

Martin Marietta Materials, Inc.

National Fuel Gas Company

Northwest Natural Gas Company

Pike Electric Corporation

Quanta Services, Inc.

Questar Corporation

Sterling Construction Company

SM Energy Company

Swift Energy Company

Texas Industries

Vectren Corporation

Vulcan Materials Company

Whiting Petroleum Corporation

EX-10.B

INSTRUMENT OF AMENDMENT TO THE

MDU RESOURCES GROUP, INC.

401(K) RETIREMENT PLAN

The MDU Resources Group, Inc. 401(k) Retirement Plan (as amended and restated March 1, 2011) (the “K-Plan”), is hereby further amended, effective January 1, 2014, unless otherwise indicated as follows:

1. By replacing the table in Section D-1-2 Eligibility to Share in the Profit Sharing Feature of Supplement D-1, Provisions Relating to the Profit Sharing Feature for certain Participating Affiliates, in its entirety, with the following:

Participating Affiliate	Current Effective Date (Original Effective Date)2
Anchorage Sand & Gravel Company, Inc. (excluding President)	January 1, 1999
Baldwin Contracting Company, Inc.	January 1, 1999
Cascade Natural Gas Corporation	January 1, 2011 (July 2, 2007)
Concrete, Inc.	January 1, 2001
Connolly-Pacific Co.	January 1, 2007
DSS Company	January 1, 2004 (July 8, 1999)
E.S.I., Inc.	January 1, 2008 (January 1, 2003)
Fairbanks Materials, Inc.	May 1, 2008
Granite City Ready Mix, Inc.	June 1, 2002
Great Plains Natural Gas Co.	January 1, 2008
Hawaiian Cement (non-union employees hired after December 31, 2005)	January 1, 2009

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Participating Affiliate	Current Effective Date (Original Effective Date)2
Intermountain Gas Company	January 1, 2011
Jebro Incorporated	November 1, 2005
Kent’s Oil Service4	January 1, 2007
Knife River Corporation - Northwest (the Central Oregon Division, f/k/a HTS)	January 1, 2010 (January 1, 1999)
Knife River Corporation - Northwest (the Southern Idaho Division)	January 1, 2010 (January 1, 2006)
Knife River Corporation - Northwest (the Southern Oregon Division)	January 1, 2012
Knife River Corporation - Northwest (the Spokane Division)	January 1, 2010 (January 1, 2006)
Knife River Corporation - Northwest (the Western Oregon Division)	January 1, 2012
Knife River Corporation - South (f/k/a Young Contractors, Inc.)	January 1, 2008 (January 1, 2007)
LTM, Incorporated	January 1, 2003
Montana-Dakota Utilities Co. (including union employees)	January 1, 2008
Oregon Electric Construction, Inc.3	March 7, 2011
Wagner Industrial Electric, Inc.	January 1, 2008
Wagner Smith Equipment Co.	January 1, 2008 (July 1, 2000)
WBI Energy, Inc.1/3	May 1, 2012

2

Participating Affiliate	Current Effective Date (Original Effective Date)2
WBI Energy Midstream, LLC1/3	July 1, 2012 (January 1, 2001)
WBI Energy Transmission, Inc.1/3	July 1, 2012 (January 1, 2009)
WHC, Ltd.	September 1, 2001

^1/Eligible employees participating in a management incentive compensation plan or an executive incentive compensation plan are not eligible for a Profit Sharing Contribution. Employees of the WBI Energy Corrosion Services division of WBI Energy Midstream, LLC are excluded from this feature.

²/In the event a Participating Affiliate adopts a Profit Sharing Feature on a date other than January 1, effective as of the date of participation in the Plan, the amount of any such contribution allocated to a Supplement D‑1 Participant shall be based upon Compensation, received while in the employ of the Participating Affiliate after the date of acquisition by the Company or any Affiliate.

³/Requirement to be an Active Employee on the last day of the Plan Year does not apply.

⁴/The following participants of Kent’s Oil Service are granted vesting service for prior years of service with Spirit Road Oils: Isaias Jaimes, Hideo Lewis, Christopher Niffenegger, Jose Padilla, George Velador, and Anthony Willis.

Explanation: This amendment removes Prairielands Energy Marketing, Inc. (PEMI) as a Participating Affiliate in Supplement D-1 (Profit Sharing Feature) of the K-Plan as of January 1, 2014 due to request to participate in the Fidelity Cash Incentive Plan.

IN WITNESS WHEREOF, MDU Resources Group, Inc., as Sponsoring Employer of the Plan, has caused this amendment to be duly executed by a member of the MDU Resources Group, Inc. Employee Benefits Committee (“Committee”) on this 13th day of March, 2014.

MDU RESOURCES GROUP, INC.
	EMPLOYEE BENEFITS COMMITTEE
By:	/s/ Doran N. Schwartz
	Doran N. Schwartz, Chairman

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EX-10.C

EXECUTION VERSION

Purchase and Sale Agreement

By and Between

Ballard Petroleum Holdings LLC

as Seller

and

Fidelity Exploration & Production Company

and Fidelity Oil Co.

as Buyer

Dated February 10, 2014

Dated Effective October 1, 2013

Converse County, Wyoming

3010138.11

TABLE OF CONTENTS
ARTICLE 1.	Purchase and Sale	1
1.1	Purchase and Sale	1
1.2	The Assets	1
1.3	Excluded Assets	3
1.4	Overriding Royalties and other Burdens	4
1.5	Effective Time	5
1.6	Revenue and Expenses	5
1.7	Section 1031 Exchanges	5
ARTICLE 2.	Purchase Price	5
2.1	Purchase Price	5
2.2	Deposit	5
2.3	Allocation of the Purchase Price	6
2.4	Adjustments to Purchase Price	6
2.5	Preliminary Settlement Statement	8
ARTICLE 3.	Due Diligence and Exclusive Offer	8
3.1	The Records	8
3.2	Information Disclaimer	9
3.3	Physical Access to the Assets	9
3.4	Buyer’s Other Due Diligence Activities	9
3.5	Exclusive Offer	9
ARTICLE 4.	Title Matters	10
4.1	Definitions	10
4.2	Purchase Price Adjustments for Title Defects	14
4.3	Interest Addition	15
4.4	General Disclaimer of Title Warranties and Representations	16
4.5	Disputes Regarding Title	16
4.6	Casualty Loss	17
4.7	Preferential Rights and Consents to Assign	17
4.8	Rentals, Minimum Royalties, and Shut-in Royalties	19
4.9	Excluded Contracts	19
ARTICLE 5.	Environmental Matters	19
5.1	Definitions	19
5.2	Environmental Assessment	21
5.3	Environmental Representation and Warranty	21
5.4	Environmental Liabilities and Obligations	22
5.5	Contested Environmental Defects	23
5.6	Exclusive Remedies	24

i

ARTICLE 6.	Seller’s Representations and Warranties	24
6.1	Company Representations	24
6.2	Liability for Brokers’ Fees	24
6.3	No Bankruptcy	24
6.4	Foreign Person	25
6.5	Litigation	25
6.6	Judgments	25
6.7	Compliance with Law	25
6.8	Material Contracts	25
6.9	Records	25
6.10	Property Expenses	25
6.11	Capital Projects	26
6.12	Leases	26
6.13	Licenses and Permits	26
6.14	Hydrocarbon Sales Contracts	26
6.15	Imbalance Volumes	26
6.16	Insurance	27
6.17	Plugging Obligations	27
6.18	Preferential Rights and Required Consents	27
6.19	Area of Mutual Interest, Tax Partnerships	27
6.20	Taxes	27
6.21	Title	27
6.22	Surface Access	27
6.23	Intellectual Property	27
ARTICLE 7.	Buyer’s Representations and Warranties	28
7.1	Corporate Representations	28
7.2	Liability for Brokers’ Fees	28
7.3	Litigation	28
7.4	Financing	28
7.5	Consents	28
7.6	Bankruptcy	29
7.7	Regulatory	29
7.8	Accredited Investor	29
7.9	Independent Evaluation	29
ARTICLE 8.	Covenants and Agreements	29
8.1	Covenants and Agreements of Seller	29
8.2	Covenants and Agreements of Buyer	30
8.3	Covenants and Agreements of the Parties	30
8.4	Suspense Accounts and Division of Interest	32
8.5	Record Retention	32
8.6	Disclaimers	32
ARTICLE 9.	Tax Matters	34
9.1	Definitions	34
9.2	Apportionment of Property Taxes	35

ii

9.3	Apportionment of Severance Taxes	36
9.4	Income Taxes	36
9.5	Transfer Taxes	36
9.6	Post-Closing Tax Matters	36
9.7	Allocations for Federal Income Tax Purposes	37
ARTICLE 10.	Conditions Precedent to Closing	37
10.1	Seller’s Conditions Precedent	37
10.2	Buyer’s Conditions Precedent	38
ARTICLE 11.	Termination	39
11.1	Termination	39
11.2	Remedies	39
ARTICLE 12.	Closing	40
12.1	Date of Closing	40
12.2	Place of Closing	41
12.3	Closing Obligations	41
ARTICLE 13.	Post-Closing Obligations	42
13.1	Final Settlement Statement	42
13.2	Financial Statements	43
13.3	Area of Mutual Interest	43
13.4	Further Assurances	43
ARTICLE 14.	Assumption and Retention of Obligations and Indemnification	44
14.1	Buyer’s Assumption of Liabilities and Obligations	44
14.2	Seller’s Retention of Liabilities and Obligations	44
14.3	Indemnification	45
14.4	Indemnification Limitations	45
14.5	Express Negligence	46
14.6	Exclusive Remedy	46
14.7	Procedure	46
14.8	Survival	47
14.9	Insurance	48
14.10	No Insurance; Subrogation	48
14.11	Reservation as to Non-Parties	48
14.12	Noncompensatory Damages	48
14.13	Disclaimer of Application of Anti-Indemnity Statutes	49
ARTICLE 15.	Miscellaneous	49
15.1	Expenses	49
15.2	Notices	49
15.3	Relationship of Buyer Entities	49
15.4	Amendments/Waiver	50
15.5	Assignment	50
15.6	Announcements	50

iii

15.7	Counterparts/Electronic Fax Signatures	50
15.8	Governing Law	50
15.9	Entire Agreement	50
15.10	Knowledge	50
15.11	Binding Effect	50
15.12	Dispute Resolution	51
15.13	References, Titles and Construction	51

iv

LIST OF EXHIBITS

Exhibit	Description
A	Transaction Area
B	Leases
C	Wells
D	Material Contracts
E	Form Assignment, Bill of Sale and Conveyance
F	Non Foreign Affidavit
G	Form of Seller’s Officer’s Certificate
H	Form of Buyer’s Officer’s Certificate

v

LIST OF SCHEDULES

Schedules	Description
2.3	Allocation Schedule
4.1B.2	Contested Tax Liens
4.1B.7	Contested Mechanics Liens
4.1B.10	Contested Liens
4.7	Preferential Rights and Required Consents
5.3	Environmental Issues
6.5	Litigation
6.6	Judgments
6.10(y)	Disputed Property Expenses
6.11	Capital Projects
6.15	Imbalances
6.16	Insurance
6.17	Plugging Obligations
6.19	Area of Mutual Interest; Tax Partnership
6.20	Tax Matters
8.4	Suspense Revenues

vi

PURCHASE AND SALE AGREEMENT

Converse County, Wyoming

This Purchase and Sale Agreement (the “Agreement”), dated February 10, 2014, but effective as of October 1, 2013, is by and between Ballard Petroleum Holdings LLC, a Montana limited liability company, whose address is 845 12th Street, Billings, Montana 59102 (“Seller”) and Fidelity Exploration & Production Company, a Delaware corporation (“Fidelity Exploration”), and Fidelity Oil Co., a Delaware corporation (“Fidelity Oil”), each of whose address is 1700 Lincoln Avenue, Suite 2800, Denver, Colorado 80203 (Fidelity Exploration and Fidelity Oil, collectively, “Buyer”). The transaction contemplated by this Agreement may be referred to as the “Transaction.” Seller and Buyer may be referred to individually as a “Party” or collectively as the “Parties.” The obligations of the companies comprising Buyer under this Agreement shall be several in the ratio of ninety-eight percent (98%) for Fidelity Exploration and two percent (2%) for Fidelity Oil.

Recitals

A.    Seller owns certain interests in oil and gas leases covering lands and certain oil and gas wells located in a portion of Converse County, Wyoming, as more particularly described on attached Exhibit A (the “Transaction Area”).

B.    Seller and Buyer desire that Buyer acquire one hundred percent (100%) of Seller’s interest in the Assets, as defined below, and all title and the rights associated therewith by paying the Purchase Price, as that term is defined below.

C.    To accomplish the foregoing, the Parties wish to enter into this Agreement.

Agreement

In consideration of the mutual promises herein, One Hundred Dollars ($100.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

ARTICLE 1.

PURCHASE AND SALE

1.1    Purchase and Sale. Seller agrees to sell and Buyer agrees to purchase the Assets pursuant to the terms of this Agreement.

1.2    The Assets. As used herein, the term “Assets” (or individually an “Asset”) refers to all (one hundred percent (100%)), of the Seller’s right, title and interest in and to the following:

A.The oil, gas and/or mineral leases described in Exhibit B (the “Leases”, or individually, a “Lease”) covering the lands described on Exhibit B, together with the lands pooled or unitized therewith (the “Lands”), and the oil, gas and other hydrocarbons produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination thereof, and any minerals (whether in liquid or gaseous form) produced in

1

association therewith (“Hydrocarbons”) in, on or under the Leases or Lands (including Hydrocarbons in storage or in pipelines, plants and tanks as of the Effective Time (as later defined)), including the leasehold estates and interests, contractual leasehold, other similar leasehold rights in the Leases or Lands, working interests, mineral interests, royalty interests, overriding royalty interests, production payments and net profits interests therein, together with the property and rights incident thereto, subject to those reservations, limitations or depth restrictions, if any, identified on such Exhibit B;

B.The oil and gas wells, water, injection and disposal wells on the Lands, or on lands pooled, communitized or unitized therewith as specifically described in Exhibit C (the “Wells”);

C.All personal property, inventory, equipment, fixtures or improvements used in connection with the exploration, drilling, production, gathering, treatment, processing, storing, transportation, sale or disposal of Hydrocarbons or water produced from the Wells and Leases or located on the Lands, including any gathering systems and any compressors owned by Seller (the “Equipment”);

D.The rights, interests and estates created under those certain servitudes, easements, rights-of-way, privileges, franchises, prescriptions, licenses, leases, permits and/or other rights associated with the Leases and Lands, together with any amendments, renewals, extensions, supplements, modifications or other agreements related thereto, and further together with any other servitudes, easements, rights-of-way, privileges, prescriptions, franchises, licenses, permits and/or other rights (whether presently existing or hereafter created and whether now owned or hereafter acquired by operation of law or otherwise) used, held for use in connection with, or in any way related to the properties and interests described in Sections 1.2A through 1.2J;

E.All permits, rights-of-way, surface access agreements and easements located on the Lands or used in connection with the exploration, drilling, production, gathering, treatment, processing, storing, transportation, sale or disposal of Hydrocarbons or water produced from the Leases and Lands;

F.The unitization, pooling and communitization agreements, declarations and orders, and the units created thereby and all other such agreements relating to the properties and interests described in Sections 1.2A through 1.2E and to the production of Hydrocarbons, if any, attributable to said properties and interests;

G.All contracts and contractual rights, obligations, and interests, including all farmout and farmin agreements, operating agreements, production sales and purchase contracts, gas balancing agreements, saltwater disposal agreements, surface leases, division and transfer orders, and other contracts or agreements covering or affecting any or all of the properties and interests described or referred to in Sections 1.2A through 1.2J (the “Contracts”), including the Contracts that are material to the ownership and operation of the Assets to which Seller is a party, or of which Seller has knowledge, as listed in Exhibit D (the “Material Contracts”);

2

H.All engineering, geologic, geophysical and seismic data and licenses pertaining to the properties and interests described in Sections 1.2A through 1.2J other than the Hornbuckle 3D Seismic Survey (the “Data”);

I.All files, records and data relating to the items described in Sections 1.2A through 1.2J maintained by Seller including, without limitation, the following, if and to the extent that such files exist: all records, files, title documents, including correspondence, records of production and maintenance, revenue, sales, expenses, warranties, lease files, land files, well files, division order files, abstracts, title opinions, assignments, reports, property records, contract files, financial statements and associated work papers and work product, which relate to the items described in Sections 1.2A through 1.2J, including work product prepared by accountants, and the reserve reports and lease operating statements for the items described in Sections 1.2A through 1.2J for the years 2011, 2012, 2013, and that portion of 2014 prior to Closing and such other records as Buyer may request or are necessary for Buyer to prepare financial statements, tax returns, and other filings, but excluding from the foregoing (i) those files, records and data subject to unaffiliated third party contractual restrictions on disclosure or transfer, (ii) work product prepared by accountants in connection with Seller’s tax planning and the preparation of Seller’s income or franchise tax returns, (iii) third party reserve reports and evaluations, and (iv) audited financial statements (after such exclusions, the “Records”). To the extent that any of the Records contain interpretations of Seller, Buyer agrees to rely on such interpretations at its own risk; and

J. All other real and personal properties, rights and titles of Seller, other than the Excluded Assets, owned by Seller and located in, or pertaining to, the Transaction Area as of the Effective Time, whether or not described in Sections 1.2A through 1.2I above, or included in an Exhibit or Schedule to this Agreement.

1.3    Excluded Assets. As used herein, the term “Excluded Assets” refers to all of Seller’s right, title and interest in and to the following, all of which are excluded from the terms of this Agreement and shall remain the sole property of Seller:

A.    All of Seller’s corporate minute books, financial records and other business records that relate to Seller’s business generally (including the ownership and operation of the Assets) and the items excluded from the Records under Section 1.2I;

B.    All trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time;

C.    To the extent they do not relate to the Assumed Obligations, all claims and causes of action of Seller arising under or with respect to any of the Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds);

D.    All rights and interests of Seller (i) under any policy or agreement of insurance or indemnity, (ii) under any bond, or (iii) to any insurance or condemnation proceeds

3

or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property prior to the Effective Time, to the extent they do not relate to the Assumed Liabilities;

E.    All Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective Time;

F.    All claims of Seller for refunds (including rights to receive refunds from any governmental entity) or loss carry forwards or credits with respect to (i) Asset Taxes (hereafter defined) allocable to Seller pursuant to Section 9.2 or Section 9.3, except to the extent such Taxes resulted in an adjustment in the final determination of the Final Purchase Price, (ii) Income Taxes of the Seller, or (iii) any Taxes attributable to the Excluded Assets;

G.    All offices, office leases of Seller, office furniture, furnishings, computer equipment, proprietary computer software, radio and telephone equipment, patents, trade secrets, copyrights, names, trademarks, logos and all other intellectual property;

H.    All documents and instruments of Seller that may be protected by an attorney/client privilege or any attorney work product doctrine, but specifically excluding title opinions;

I.    Any and all files, records, and documents relating to Seller’s sale of the Assets, including any research, valuation or pricing information prepared by Seller and/or any consultants for Seller in connection with Seller’s efforts to sell the Assets, and any offers received for such interests and information and correspondence in connection therewith;

J.    All engineering, geophysical and other seismic and related technical data and information relating to the Assets which Seller may not disclose, assign or transfer under its existing agreements and licenses without consent or without making an additional payment, or incurring any liabilities or obligations except to the extent that such payments, liabilities and obligations are permitted to be assumed by Buyer under the applicable agreements and the same are assumed by Buyer;

K.Any debt instruments;

L.Any of the Assets described in Section 1.2E, Section 1.2G, Section 1.2H or Section 1.2I that are not assignable, without consent or without making any additional payments, or incurring any liabilities or obligations except to the extent that such payments, liabilities and obligations are permitted to be assumed by Buyer under the applicable agreements and the same are assumed by Buyer;

M.The Hornbuckle 3D Seismic Survey; and

N.All other properties, interests and rights expressly reserved to the Seller and that are excluded from the Transaction under other provisions of this Agreement.

1.4    Overriding Royalties and other Burdens. As of the Effective Time, Seller has not and will not reserve or transfer an overriding royalty interest or otherwise burden the Assets, except that Seller has previously reserved an overriding royalty interest under the Helis

4

Agreement (as later defined) which is to be transferred to Buyer as part of the Assets (the “Helis Overriding Royalty”).

1.5    Effective Time. The purchase and sale of the Assets shall be effective as of October 1, 2013, at 7:00 a.m. Mountain Daylight Time (the “Effective Time”).

1.6    Revenue and Expenses. Subject to the provisions hereof, Seller shall (i) remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and all other income, proceeds, receipts and credits) and (ii) remain responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Property Expenses (as later defined), in each case, attributable to the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, and subject to the occurrence of Closing, Buyer shall (iii) be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds), and (iv) be responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Property Expenses, in each case, attributable to the Assets for the period of time from and after the Effective Time.

1.7    Section 1031 Exchanges. Seller reserves the right, at or prior to Closing, to assign its rights to all or a portion of the Purchase Price, and that portion of the Assets associated therewith (“1031 Assets”), to a Qualified Intermediary (as that term is defined in Section 1.1031(k)-1(g)(4) of the Treasury Regulations) (the “QI”) to accomplish this transaction, in whole or in part, as a like-kind exchange (“Like-Kind Exchange”) under Section 1031 of the Internal Revenue Code of 1986, as amended (“Code”). Buyer hereby (i) consents to Seller’s assignment of its rights in this Agreement to the 1031 Assets, and (ii) if such an assignment is made, provided Buyer received timely notice thereof, Buyer agrees to pay all or a portion of the Purchase Price into a qualified trust account at Closing as directed in writing by Seller. Buyer likewise reserves the right, at or prior to Closing, to assign all or a portion of its rights in this Agreement to a QI or to Buyer’s Exchange Accommodation Titleholder (as that term is defined in Revenue Procedure 2000-37) (the “EAT”) in connection with effecting a Like-Kind Exchange. Seller and Buyer acknowledge and agree that a whole or partial assignment of this Agreement to a QI or EAT shall not release either Party from or expand any of their respective liabilities and obligations to each other under this Agreement. Neither Party shall be obligated to pay any additional costs or incur any additional obligations as a result of any Like-Kind Exchange effected by the other Party and each Party agrees to hold harmless and indemnify the other Party from and against all claims, losses and liabilities, if any, resulting from such Like-Kind Exchange.

ARTICLE 2.

PURCHASE PRICE

2.1    Purchase Price. The “Purchase Price” for the Assets shall be Ninety-One Million Five Hundred Thousand Dollars ($91,500,000.00).

2.2    Deposit. Contemporaneously with the execution of this Agreement, Buyer has deposited with Seller by wire transfer in same day funds, the sum of Two Million Dollars ($2,000,000.00) (the “Deposit”). The Deposit shall be distributed to Seller and credited to the

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Purchase Price at Closing, or if this Agreement is terminated, shall be distributed or retained pursuant to Article 11.

2.3    Allocation of the Purchase Price. Buyer, with Seller’s approval, has allocated the Purchase Price among the Assets as set forth on Schedule 2.3. The value so allocated to a particular Asset or spacing unit may be referred to as the “Allocated Value” for that Asset.

2.4    Adjustments to Purchase Price. All adjustments to the Purchase Price shall be made (i) according to the factors described in this Section 2.4, (ii) in accordance with generally accepted accounting principles as consistently applied in the oil and gas industry, and (iii) without duplication.

A.    Closing Amount. The term “Closing Amount” means the Purchase Price, less the Deposit, adjusted as provided in this Section 2.4, using reasonable estimates as agreed to by the Parties if actual numbers are not available.

B.    Property Expenses. For the purposes of this Agreement, the term “Property Expenses” shall mean all capital expenses (including amounts paid, leases acquired and other capital expenditures incurred after the Effective Time), and all other direct and actual expenses attributable to the Assets, including, without limitation, joint interest billings, lease operating expenses, third party overhead charges, lease rental and maintenance costs, royalties, overriding royalties, leasehold payments, Asset Taxes (as defined and apportioned as of the Effective Time pursuant to Article 9), drilling expenses, workover expenses, gathering costs, geological, geophysical and any other exploration or development expenditures chargeable under applicable operating agreements or other agreements consistent with the standards established by the Council of Petroleum Accountant Societies of North America that are attributable to the maintenance and operation of the Assets during the period in question. In no event will Property Expenses include any costs or expenses of any kind associated with Seller’s efforts to sell or market the Assets.

C.    Upward Adjustments. The Purchase Price shall be adjusted upward by the following:

1.An amount equal to all proceeds (net of royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons and Taxes not otherwise accounted for hereunder) received and retained by the Buyer from the sale of all Hydrocarbons produced from or credited to the Assets prior to the Effective Time;

2.An amount equal to all Property Expenses incurred and paid by Seller that are attributable to the period after the Effective Time;

3.To the extent not covered in the preceding paragraph, an amount equal to all prepaid expenses attributable to the Assets after the Effective Time, whether paid before, on, or after the Effective Time, that were paid by or on behalf of Seller, including applicable insurance costs, prepaid drilling and/or completion costs, and prepaid utility charges;

4.An amount equal to the Interest Addition Adjustment;

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5.An amount equal to the value of all Hydrocarbons in storage or in the pipelines, plant and tanks as of the Effective Time that is credited or attributable to the Assets; provided that the value of oil in the production tanks shall be calculated to include only the oil stored above the load lines as of the Effective Time (i.e. Buyer is not responsible for paying Seller “tank bottoms”) and the value (i) for purposes of the Preliminary Settlement Statement, to be the actual price received for such oil, gas, or natural gas liquids, less applicable Taxes, upon the first unaffiliated third party sale thereof, if available, and upon such estimates, as are reasonably agreed upon by the Parties, to the extent actual amounts sold, or to be sold, and prices obtained, or to be obtained, are not known at Closing, and (ii) for purposes of the Final Settlement Statement, to be based upon actual amounts sold and prices obtained, less applicable Taxes, from the first unaffiliated third party sale thereof;

6.An amount equal to the value of imbalances including, without limitation, pipeline, plant, and under-produced gas owed to Seller as of the Effective Time, with the value (i) for the purposes of the Preliminary Settlement Statement, to be the actual price received for such Hydrocarbons to be based upon actual amounts received in October of 2013, if available, and upon such estimates as are reasonably agreed upon by the Parties, to the extent actual amounts are not known at Closing, and (ii) for purposes of the Final Settlement Statement, to be based upon actual amounts sold and prices received in October 2013; and

7.Any amounts provided elsewhere in this Agreement and any other amount agreed to by Buyer and Seller.

D.    Downward Adjustments. The Purchase Price shall be adjusted downward by the following:

1.    An amount equal to all proceeds (net of royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons and Taxes not otherwise accounted for hereunder) received and retained by the Seller from the sale of all Hydrocarbons produced from or credited to the Assets after the Effective Time;

2.    An amount equal to all Property Expenses that remain unpaid by Seller, or that have been paid by Buyer, and that are attributable to the period prior to the Effective Time;

3.    An amount equal to all cash in, or attributable to, suspense accounts held by Seller relating to the Assets for which Buyer has accepted responsibility at Closing pursuant to Section 8.4;

4.    An amount equal to (i) the value of imbalances including, without limitation, pipeline, plant, and over-produced gas owed by Seller as of the Effective Time, with the value to be based upon actual amounts received in October of 2013, if available, and upon such estimates as are reasonably agreed upon by the Parties, to the extent actual amounts are not known at Closing, and (ii) for purposes of the Final Settlement Statement, be based upon actual amounts received;

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5.    An amount equal to the Title and Environmental Defects Adjustment (hereafter defined);

6.    An amount equal to the Exclusion Adjustments (hereafter defined); and

7.    Any other amounts provided elsewhere in this Agreement, and any other amount agreed to by Buyer and Seller.

E.    Tax Adjustments. To adjust the Purchase Price for the apportionment of Taxes, the Parties agree to adjust the Purchase Price downward or upward, as appropriate, pursuant to the provisions of Article 9.

2.5    Preliminary Settlement Statement. The Purchase Price shall be adjusted at Closing pursuant to a “Preliminary Settlement Statement” prepared by Seller, submitted to Buyer, subject to Section 13.1, on or before the date that is three (3) calendar days prior to Closing. The Preliminary Settlement Statement shall set forth the Purchase Price and all adjustments thereto using the actual numbers that are available, and the resulting amount, less the Deposit, will be paid to Seller at Closing, together with the designation of Seller’s account for the wire transfer of same day funds. As soon as practicable after the receipt of the Preliminary Settlement Statement, but in no event later than the date that is one (1) calendar day prior to Closing, Buyer shall deliver to Seller a written report containing any changes that Buyer proposes to make to the Preliminary Settlement Statement. The Parties shall attempt to resolve any disputes regarding the Preliminary Settlement Statement prior to Closing. Disputes regarding the Preliminary Settlement Statement that are not resolved prior to Closing shall be resolved by the Parties on or before the Final Settlement Statement Due Date, or otherwise pursuant to Section 13.1, and the amount of such adjustments to the Purchase Price at Closing shall be that amount set forth in the written report containing Buyer’s proposed changes to the Preliminary Settlement Statement delivered by Buyer to Seller as provided in this Section 2.5, but adjusted upwards or downwards for any items that have been resolved by the Parties prior to Closing. After Closing, the Purchase Price shall be adjusted pursuant to the Final Settlement Statement delivered pursuant to Section 13.1.

ARTICLE 3.

DUE DILIGENCE AND EXCLUSIVE OFFER

3.1    The Records. From the date of this Agreement until Closing and subject to Section 8.3A, Section 8.3B and Section 8.3C, Seller will make the Records and Contracts available to Buyer for inspection, copying, and review at Seller’s offices during normal business hours to permit Buyer to perform its due diligence review. Subject to the consent and cooperation of third parties, including but not limited to the Operator (hereafter defined), Seller will use commercially reasonable efforts to assist Buyer to obtain, at Buyer’s expense, such additional information from such third parties as Buyer may reasonably desire. Buyer may inspect the Records, Contracts and such additional information only to the extent it may do so without violating any obligation of confidence or contractual commitment of Seller to a third party. Buyer acknowledges that certain third parties, not Seller, are the operators with respect to all of the Assets (each an “Operator” and together the “Operators”). As a result, pertinent

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information regarding the Assets may have to be obtained from the respective Operator, which Seller shall use commercially reasonable efforts to assist Buyer to obtain.

3.2    Information Disclaimer. Except for the representations and warranties contained in this Agreement, Seller makes no representation or warranties of any kind as to the Records, the Contracts, or any other information reviewed by Buyer. Subject to (y) the items that were excluded to arrive at the definition of Records, and (z) the items constituting the Excluded Assets, Seller represents that during the Buyer’s inspection it has not, and will not, withhold any Records, Contracts, or other information in its possession of any kind related to its ownership of the Assets, or the environmental condition or value of the Assets. Buyer agrees that any conclusions drawn from its review of the Records, Contracts and other information shall be the result of its own independent review and judgment.

3.3    Physical Access to the Assets. During reasonable business hours, Seller agrees to grant Buyer physical access to the Assets to allow Buyer to conduct, at Buyer’s sole risk and expense, on-site inspections or environmental assessments of the Assets. In connection with any on-site inspections and assessments of the Assets, Buyer agrees not to interfere with the normal operation of the Assets and agrees to comply with all operational and safety requirements of the Operators of the Assets. In connection with granting such access, Buyer represents that it is adequately insured and waives, releases and agrees to indemnify, defend and hold harmless Seller, and its directors, officers, shareholders, employees, agents, members, partners, and representatives against all claims for injury to, or death of, persons or for damage to property arising in any way from the access afforded to Buyer hereunder or the Operators or the activities of Buyer except to the extent resulting from the gross negligence or willful misconduct of Seller. This waiver, release and indemnity by Buyer shall survive termination of this Agreement. Seller will use commercially reasonable efforts pursuant to its rights under the applicable joint operating agreement to assist Buyer to obtain access rights from the respective Operator for Buyer to conduct its investigation and due diligence of the Assets under this Section 3.3; provided that Seller shall not be required to incur any liability or pay any money in order to assist Buyer to obtain such access rights. Upon completion of Buyer’s due diligence, Buyer will, at its sole costs and expense and without any cost or expense to Seller (i) repair all damage done to the Assets in connection with Buyer’s due diligence and restore the Assets to at least the approximate same condition as they were in prior to commencement of Buyer’s due diligence, and (ii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. The preceding sentence will survive the termination of this Agreement.

3.4    Buyer’s Other Due Diligence Activities. In addition to Buyer’s rights provided in Section 3.3, Seller acknowledges that Buyer will be conducting other due diligence reviews of the Assets including, without limitation, confirming (i) the quantum of the Net Revenue Acres of the Leases, and the Base NDI and Base WI of the Wells, (ii) financials, production statements and the Records, and (iii) ownership, title, acreage, and terms of the Assets.

3.5    Exclusive Offer. Upon execution of this Agreement, Seller shall not offer the Lands and Leases as described herein, entertain offers from, or negotiate for the sale of the Lands and Leases as described herein, to any third party prior to Closing or the termination of this Agreement.

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ARTICLE 4.

TITLE MATTERS

4.1    Definitions.

A.    Defensible Title. The term “Defensible Title” means such title to the Assets, that, subject to and except for Permitted Encumbrances:

1.    entitles Seller to receive the Net Decimal Interest share of the Hydrocarbons produced, saved and marketed from any Well throughout the duration of the productive life of such Well or such specified zone(s) therein of not less than the Net Decimal Interest shown in Exhibit C for such Well. As used in this Agreement, “Net Decimal Interest” (or “NDI”) with respect to a Well shall mean (i) Seller’s percentage share of the Hydrocarbons produced, saved and marketed from the Leases located within the spacing unit of such Well, after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons, multiplied by (ii) Seller’s Working Interest (as defined herein) in the Leases located within the spacing unit of such Well. The Net Decimal Interest for each Well as set forth on Exhibit C (which includes the Helis Overriding Royalty or any other overriding royalty interest in the Leases owned by Seller (unless expressly excluded pursuant to Section 1.3), where applicable) is referred to herein as the “Base NDI”). The Base NDI, which may be adjusted due to (i) decreases in connection with those operations which Seller has elected or may elect to be a non-consenting co-owner, in compliance with Section 8.1B, or (ii) decreases resulting from the establishment or amendment of pools or units, but in each case, to the extent occurring after the Effective Time and not otherwise reflected in Exhibit C is referred to herein as the “Adjusted NDI ”.

2.    obligates Seller to bear a percentage of the costs and expenses for the maintenance, development, operation and production relating to any Well throughout the productive life of such Well (“Working Interest” or “WI”) not greater than the Working Interest shown in Exhibit C for such Well (the “Base WI”) without increase, except (i) increases to the extent that they are accompanied by a proportionate increase in Seller’s Base NDI (or Adjusted NDI, if applicable), (ii) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements occurring after the Effective Time and not otherwise reflected in Exhibit C (such increases the “WI Adjustments”). The Base WI for each Well on Exhibit C, as adjusted by such Well’s WI Adjustments, will be referred to in this Agreement as the Well’s“Adjusted WI.”

3.    entitles Seller, and will entitle Buyer after Closing, to own the Net Revenue Acres in the Leases as set forth in Exhibit B. As used in this Agreement, “Net Revenue Acres” or “NRA” with respect to a Lease shall mean (i) the number of gross acres in the lands covered by the Lease, multiplied by (ii) the lessor’s percentage interest in the oil and gas fee mineral estate in the lands covered by the Lease, multiplied by (iii) Seller’s percentage leasehold interest in the Lease, multiplied by (iv) Seller’s share of the Hydrocarbons produced, saved and marketed from such Lease after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons;

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4.    entitles Seller to own its proportionate interest in all depths pertaining to the “Frontier Formation”, being the stratigraphic interval from 12,800 feet to 13,033 feet, as found in the Diamond Shamrock Co. Henry Federal 23-10 well (API No. 4900922066), located in the SW/4NE/4SW/4 of Section 10, Township 37 North, Range 74 West;

5.    is free and clear of any liens, burdens or encumbrances of any kind or character, including any surface use restriction, that would materially interfere with the operation or use of any of the Asset or materially reduce the value thereof; and

6.    is deducible from the public record (including the records of the Bureau of Land Management or the State of Wyoming - Office of State Lands) and is free from reasonable doubt to the end that a prudent person engaged in the business of ownership, development, and operation of oil and gas leases with knowledge of all the facts and their legal bearing would be willing to accept the same without adjustment to the Purchase Price.

B.    Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

1.    lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to (i) reduce the Net Revenue Acres covered by a Lease below the Net Revenue Acres for such Lease as shown on Exhibit B, (ii) reduce the NDI for such Well below the Base NDI (or Adjusted NDI, if applicable) for such Well, or (iii) increase the Base WI for such Well without a corresponding increase in the Base NDI (or Adjusted NDI, if applicable) for such Well, in each case;

2.    liens for Taxes or assessments not yet due and delinquent, or that are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are set forth on Schedule 4.1.B.2;

3.    all rights to consent by, required notices to, filings with, or other actions by federal, state or local governmental bodies, in connection with the conveyance of the applicable Asset if the same are customarily obtained after such conveyance;

4.    rights of reassignment upon the surrender or expiration of any Lease;

5.    the terms and conditions of the Contracts and all documents of record to the extent such do not (i) reduce the Net Revenue Acres covered by a Lease below the Net Revenue Acres for such Lease as shown on Exhibit B, (ii) decrease the Base NDI (or Adjusted NDI, if applicable) or increase the Base WI (or Adjusted WI, if applicable) for the affected Well, or (iii) materially interfere with the operation or use of the affected Lease or Well as has been conducted in the past;

6.    easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, on, over or in respect of any of the Assets or any restriction on access thereto that do not materially interfere with the operation or use of the affected Asset as has been conducted in the past or materially affect the value thereof;

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7.    materialmen’s, mechanics’, operators’ or other similar liens arising in the ordinary course of business incidental to operation of the Assets (i) if such liens and charges have not been filed pursuant to law and the time for filing such liens and charges has expired or (ii) if filed, such liens and charges have not yet become due and payable or are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are described on Schedule 4.1.B.7;

8.    any encumbrance on or affecting the Assets which is discharged by Seller at or prior to Closing;

9.    all rights reserved to or vested in any municipality or governmental statutory or public authority to control or regulate any of the Assets or the operations with respect thereto in any manner, and all applicable laws, rules and orders of any such authority which are not such as to materially interfere with the operation or use of any of the Assets or materially reduce the value thereof; and

10.    liens created under the Assets or operating agreements or by operation of law in respect of obligations that are not due, or that are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are described on Schedule 4.1.B.10.

C.    Title Defect. The term “Title Defect” means any lien, encumbrance, claim, defect in or objection to real property title, excluding Permitted Encumbrances, that alone or in combination with other defects renders the Seller’s title to the Asset, including an individual Lease or Well, to be (i) less than Defensible Title, and (ii) the Title Defect Value of which is more than Twelve Thousand Five Hundred Dollars ($12,500.00) (with such amount being the “Individual Title Threshold”). In the event a Title Defect impacts multiple Assets, the Buyer may, in its sole discretion, aggregate the Title Defect Value of all Assets impacted by the Title Defect for the purposes of determining the Individual Title Threshold. Notwithstanding the foregoing, the following shall not be considered Title Defects:

1.    defects in the chain of title, consisting of the failure to recite marital status in a document or omissions of heirship or estate proceedings, unless Buyer provides reasonable written evidence that such failure or omission has resulted in another party claiming title to the relevant Asset;

2.    defects based upon unsubordinated Deeds of Trust or Mortgages on minerals so long as such Deeds of Trust or Mortgages were granted after the date the Lease covering such minerals was executed;

3.    defects arising out of lack of survey;

4.    defects that have been cured under applicable statutes of limitation for adverse possession or for prescription, or under Wyoming’s Marketable Title statute, Wyo. Stat. §§ 34‑10‑101, et. seq.;

5.    defects or irregularities arising out of the lack of recorded powers of attorney from corporations to execute and deliver documents on their behalf;

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6.    proof of representative capacity on behalf of a corporation, partnership, limited liability company or trust, unless it is clear from other documentation that a signatory party has not signed a document in the proper representative capacity;

7.    defects in acknowledgments;

8.    defects arising out of a lack of corporate or other entity authorization unless Buyer provides a reasonable basis for the assertion that such corporate or other entity action was not authorized and results in another person’s actual or superior claim of title to the relevant Asset;

9.    defects based upon failure to record leases issued by the Bureau of Land Management or the State of Wyoming - Office of State Lands in the real property records of the county in which the land covered by such leases is located;

10.    defects or irregularities arising out of prior oil and gas leases which have not been released of record, which on their face, expired more than, and no production attributable thereto has been reported to the Wyoming Oil and Gas Conservation Commission during the, five (5) years prior to the Effective Time (as long as Buyer does not provide evidence that such leases have been maintained by continuous production);

11.    such Title Defects as have been waived by Buyer; and

12.    defects based solely on: (i) lack of information in Seller’s files; or (ii) reference to an unrecorded document to which Seller, or a predecessor of Seller, or the Operator is not a party and which is not in the Records.

D.    Title Defect Value. “Title Defect Value” means the amount by which the Allocated Value of an Asset has been reduced by a Title Defect. In determining the Title Defect Value, the Parties intend to include only that portion of the Asset affected by the Title Defect. The Title Defect Value may not exceed the Allocated Value of the Asset and shall be determined by the Parties in good faith taking into account all relevant factors including, without limitation, the following:

1.    If the Title Defect is based upon the Seller’s owning an NDI (the “Corrected NDI”) which is less than the Base NDI (or Adjusted NDI, if applicable) for a Well, then the Title Defect Value shall be equal to the Allocated Value of the Asset multiplied by a fraction, the numerator of which is the difference between the Base NDI (or Adjusted NDI, if applicable) and the Corrected NDI and the denominator of which is the Base NDI (or Adjusted NDI, if applicable) for the Well.

2.    If the Title Defect is that the actual Net Revenue Acres covered by a Lease is less than the number of Net Revenue Acres set forth in Exhibit B for such Lease, the Title Defect Value shall be an amount equal to such difference in Net Revenue Acres multiplied by a fraction, the numerator of which is the Allocated Value of the affected Lease, and the denominator of which is the number of Net Revenue Acres set forth in Exhibit B for the affected Lease.

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3.    If the Title Defect is based on an obligation or burden that is liquidated in amount, the adjustment will be the sum necessary to remove the obligation or burden from the affected Asset; provided, however, that the adjustment shall never exceed the Allocated Value of the affected Asset.

4.    If the Title Defect is based on an obligation or burden that is not liquidated in amount (including, but not limited to, any increase in the Base WI (or Adjusted WI, if applicable) for which there is not a proportionate increase in the Base NDI (or Adjusted NDI, if applicable)), but can be estimated with reasonable certainty, the adjustment will be the sum necessary to compensate Buyer on the Closing Date for the adverse economic effect on the affected Asset; provided, however, that the adjustment shall never exceed the Allocated Value of the affected Asset.

5.    If the Title Defect (taking into account Seller’s interest in all Leases covering the same Lands) is based on a lack of rights to the Frontier Formation, the Title Defect Value shall be 66.67% of the Allocated Value of the affected Asset.

6.    If the Title Defect is a lien or encumbrance on the Asset created by Seller, Seller shall have the lien or encumbrance unconditionally released prior to Closing and if so released, there shall be no Title Defect Value associated with such lien or encumbrance.

4.2    Purchase Price Adjustments for Title Defects.

A.    Notices of Title Defects. Buyer shall give Seller a written “Title Defect Notice” on or before 5:00 p.m. Mountain Time on February 28, 2014, (the “Title Defect Date”). To be effective, each Title Defect Notice must be in writing and must satisfy the following conditions precedent: (i) name the affected Asset; (ii) describe each Title Defect in reasonable detail; (iii) describe the basis for each Title Defect; (iv) attach Supporting Documentation; (v) state the Allocated Value of the affected Asset; (vi) state Buyer’s good faith estimate of the Title Defect Value; and (vii) set forth the computations upon which Buyer’s estimate is based. For the purposes of this Section 4.2A, “Supporting Documentation” for a particular Title Defect means the following: (x) if the basis is derived from any document, a copy of such document (or pertinent part thereof); (y) if the basis is derived from any gap in Seller’s chain of title, the documents preceding and following the gap shall be attached, or in any case, other reasonable written documentation, or (z) if the basis is derived from a title opinion, then a copy of the pertinent title comment and requirement from that opinion. Buyer shall be deemed to have waived, for all purposes of this Agreement, and Seller shall have no liability for, any Title Defect existing prior to the Title Defect Date which Buyer failed to assert as a Title Defect by a properly delivered Title Defect Notice received by Seller on or before the Title Defect Date, except that for purposes of the special warranty of title in the Assignment Buyer shall be deemed to have waived only those Title Defects existing prior to the Title Defect Date (which would otherwise be subject to such special warranty) of which Buyer had knowledge, but failed to notify the Seller of on or before the Title Defect Date.

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B.    Defect Adjustments.

1.    The Purchase Price will be reduced under Section 2.4 and as set forth below, unless: (i) Seller cures, at Seller’s sole cost and expense, the Title Defect prior to Closing to Buyer’s reasonable satisfaction; (ii) Buyer agrees to waive the relevant Title Defect, which waiver may be withheld by Buyer in Buyer’s sole discretion; or (iii) Seller elects on or before Closing, to attempt to cure to Buyer’s reasonable satisfaction such Title Defect, at Seller’s sole cost and expense, no later than the Final Settlement Statement Due Date (as later defined).

2.    There shall not be any adjustment to the Purchase Price or other remedies available to Buyer (i) for any individual Title Defect for which the Title Defect Value does not exceed the Individual Title Threshold; and (ii) in no event shall there be any adjustment to the Purchase Price or other remedies available to Buyer for Title Defects that exceed the Individual Title Threshold unless (A) the sum of (1) the aggregate Title Defect Values of all such Title Defects that exceed the Individual Title Threshold (but excluding any such Title Defects (I) which are cured by Seller prior to Closing, (II) waived by the Buyer, or (III) with respect to Assets which are deemed to be Excluded Assets, other than as provided in Section 1.3) (the “1 Amount”) plus (2) the aggregate of all Environmental Defect Values that exceed the Individual Environmental Threshold (but excluding any Environmental Defects (I) which are Remediated by Seller, or (II) waived by the Buyer) (the “2 Amount”), exceeds (B) One Million Three Hundred Thousand ($1,300,000.00) (the “Aggregate Deductible”), after which Buyer will be entitled to an adjustment of the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the sum of the 1 Amount plus the 2 Amount exceeds the Aggregate Deductible (the “Title and Environmental Defects Adjustment”). Notwithstanding the foregoing, with respect to any Title Defect described in Section 4.1D.5, the Title and Environmental Defects Adjustment shall include the Title Defect Value of such Title Defect, first dollar, without regard to the Individual Title Threshold or Aggregate Deductible.

3.    If prior to Closing Seller elects to cure the relevant Title Defect post-Closing, the affected Asset shall not be assigned to Buyer at Closing and the Purchase Price will be reduced by the Allocated Value of such affected Asset. Seller shall have until the Final Settlement Statement Due Date to attempt to cure such Title Defect, and shall deliver evidence that any Title Defects have been cured prior to the Final Settlement Statement Due Date. Following the Final Settlement Statement Due Date, Seller shall assign to Buyer (in substantially the same form as the Assignment) the Assets affected by a Title Defect that Seller elected to cure post-Closing, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Title Defect Value of any Title Defect that has not been cured to Buyer’s reasonable satisfaction, subject to Section 4.2B.2, provided however, if the Title Defect Value equals 100% of the Allocated Value of the affected Asset, unless the Parties otherwise agree, Seller may retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

4.3    Interest Addition. Promptly on discovery, but on or before the Title Defect Date, Buyer shall in good faith notify Seller, or Seller shall in good faith notify Buyer, of any Interest Addition. As used in this Agreement an “Interest Addition” shall mean, (i) any right title or interest of Seller in any real or personal property located within or used in connection with the

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Transaction Area, other than the Excluded Assets, that are not listed on Exhibit B or Exhibit C, (ii) any interest that entitles Seller to receive (y) more than the Net Revenue Acres identified on Exhibit B for any particular Lease, (z) a higher Base NDI (or Adjusted NDI, if applicable), in any particular Well than the Base NDI (or Adjusted NDI, if applicable) for the Well, provided such increase is equal to or in excess of any proportionate increase in the Base WI (or Adjusted WI, if applicable) for such Well, or (iii) a lesser Base WI in any particular Well than the Base WI (or Adjusted WI, if applicable) for the Well, provided such decrease is in excess of any proportionate decrease in the Base NDI (or Adjusted NDI, if applicable) for such Well. Each such notice of an Interest Addition shall be in writing and shall describe the Interest Addition, the estimated Allocated Value for the Interest Addition, or the amount by which the Allocated Value of the Asset has been increased by the Interest Addition (“Value of Interest Addition”), together with the associated computations and supporting documentation. The Parties shall determine the Value of the Interest Addition in good faith in the same manner as provided in Section 4.1D, taking into account all relevant factors. The Purchase Price shall be increased for only those Value of Interest Additions that exceed the Individual Title Threshold and only to the extent the aggregate value of all Value of Interest Additions that exceed the Individual Title Threshold exceeds Six Hundred Fifty Thousand Dollars ($650,000.00) (the “Section 4.3 Aggregate Deductible”) after which Seller will be entitled to an adjustment of the Purchase Price but only with respect to the amount by which the sum of all Value of Interest Additions exceed the Section 4.3 Aggregate Deductible (with the amount of such adjustment being the “Interest Addition Adjustment”).

4.4    General Disclaimer of Title Warranties and Representations. Except for the representations and warranties contained in this Agreement and the special warranty of title set forth in the Assignment, Seller makes no representation and warranty, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any Asset (i) in existence before the Title Defect Date, shall be as set forth in Section 4.2 or Section 4.5 or, if applicable, Section 11.1C and (ii) after the Title Defect Date, shall be pursuant to the special warranty of title set forth in the Assignment as provided in Section 4.2A.

4.5    Disputes Regarding Title. In the event of a dispute concerning (i) the scope or validity of a Title Defect, (ii) the Title Defect Value of a Title Defect, (iii) Seller’s cure of any Title Defect to the reasonable satisfaction of Buyer, (iv) the scope and validity of an Interest Addition, (v) the Value of Interest Additions, or (vi) any other matter relating to title to the Assets (a “Title Disputed Matter”), the principals of each of Buyer and Seller capable of making a final binding decision for each Party shall meet in person at the offices of Buyer, at least one (1) calendar day prior to Closing, and attempt to resolve such Title Disputed Matter. If resolution is not achieved during that meeting, then the Asset affected by such Title Disputed Matter shall not be assigned to Buyer at Closing, the Purchase Price will be reduced by the Allocated Value of such affected Asset, and such Title Disputed Matter will be determined by binding arbitration, with a single arbitrator mutually acceptable to Seller and Buyer who is licensed to practice law in the State of Wyoming and who has at least ten (10) years of mineral title examination experience (the “Title Arbitrator”). The arbitration will occur as soon as is practicable but in any event within thirty (30) days following designation of the Title Arbitrator, and the Title Arbitrator will issue a decision within ten (10) business days following completion of the arbitration. If the Parties are unable to agree upon the Title Arbitrator within ten (10) days

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of the Parties’ meeting, then either Party may apply to the court of the Eighth Judicial District in and for Converse County, Wyoming, for the appointment of the Title Arbitrator pursuant to Wyo. Stat. § 1-36-101, et seq., of the Wyoming Uniform Arbitration Act. The fees charged by the Title Arbitrator shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. Upon issuance of the Title Arbitrator’s decision, Seller shall promptly assign to Buyer (in substantially the same form as the Assignment) the Assets affected by the Title Disputed Matter, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Title Defect Value of any Title Defect that has not been cured to Buyer’s reasonable satisfaction subject to Section 4.2B.2, consistent with the Title Arbitrator’s decision, provided however, if the Title Defect Value (consistent with the Title Arbitrator’s decision) equals 100% of the Allocated Value of the affected Asset, unless the Parties otherwise agree, Seller may retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

4.6    Casualty Loss.

A.    Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and the depreciation of personal property due to ordinary wear and tear, in each case with respect to the Assets, and Buyer shall not assert any such matter as Casualty Losses (as later defined) or Title Defects under this Agreement.

B.    Prior to Closing, if a portion of the Assets is destroyed by fire or other casualty, or is taken or threatened to be taken in condemnation or under the right of eminent domain (with such event being a “Casualty Loss”), Buyer shall purchase the Asset at Closing for the Allocated Value of the Asset, reduced by an amount equal to the difference between (i) the estimated cost to repair or replace such Asset (with equipment of similar utility), less (ii) any insurance proceeds which Seller pays or causes to be paid to Buyer, up to the Allocated Value thereof (the reduction being the “Net Casualty Loss”). At its sole option, Seller may elect to cure such Casualty Loss prior to Closing, and in such event Seller shall be entitled to all insurance proceeds. If Seller elects to cure such Casualty Loss, Seller may replace any personal property that is the subject of a Casualty Loss with equipment of similar grade and utility. If Seller cures the Casualty Loss prior to Closing, Buyer shall purchase the affected Asset at Closing for the Allocated Value thereof without any Purchase Price Adjustment for such Casualty Loss.

4.7    Preferential Rights and Consents to Assign. To Seller’s knowledge, all preferential purchase rights and consents to assign affecting the Assets, except governmental consents that are customarily obtained after Closing, are set forth on Schedule 4.7. “Required Consents” include all consents and approvals except those governmental approvals which are customarily obtained post-Closing. To the extent that there are preferential purchase rights or consents to assign affecting the Assets, the provisions of this Section 4.7 shall apply. Seller shall use its commercially reasonable efforts to obtain all consents to assign. If Buyer discovers a consent to assign or preferential right to purchase during the course of Buyer’s due diligence activities that is not listed on Schedule 4.7, Buyer shall notify Seller immediately, and Seller

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shall use commercially reasonable efforts to obtain such consents or waivers and to give the notices required in connection with the preferential rights prior to Closing.

A.    Required Consents. Except with respect to the Required Consents that are conditions precedent to the Parties’ obligation to close under Article 10, as to any Asset affected by any other Required Consent that has not been obtained as of the Closing: (i) the portion of the Assets for which such Required Consent has not been obtained shall not be conveyed at the Closing; (ii) the Allocated Value for that Asset (or such portion thereof) shall not be paid to Seller; and (iii) Seller shall use commercially reasonable efforts to obtain such Required Consent as promptly as possible following Closing. If such Required Consent has been obtained as of the Final Settlement Statement Due Date, Seller shall convey the affected Asset to Buyer effective as of the Effective Time and Buyer shall pay Seller the Allocated Value of the affected Asset. If such Required Consent has not been obtained as of the Final Settlement Statement Due Date, the affected Asset shall be deemed to be an Excluded Asset. Buyer shall reasonably cooperate with Seller in obtaining any Required Consent including providing assurances of reasonable financial conditions, but Buyer shall not be required to expend funds or make any other type of financial commitments a condition of obtaining such consent.

B.    Preferential Purchase Rights. If the Parties cannot obtain a waiver of a preferential right to purchase any portion of the Assets before Closing, then the following provisions shall apply:

1.    If any preferential right to purchase is exercised and consummated prior to the Closing Date, that portion of the Assets affected by such preferential purchase right shall be an Excluded Asset and the Purchase Price shall be adjusted downward by an amount equal to the Allocated Value of such affected Assets without the requirement for Buyer to give notice.

2.    If by Closing, the time frame for the exercise of such preferential purchase rights has not expired and Seller has not received notice of an intent not to exercise or a waiver of the preferential purchase right, then Seller will retain the portion of the Assets affected by the preferential purchase right and the Purchase Price will be reduced by the Allocated Value (or a portion of the Allocated Value) for the portion of the Assets affected by the preferential purchase right. If, prior to the Final Settlement Statement Due Date, the preferential purchase right has expired without having been exercised, or has been waived, then Seller will convey the portion of the Assets affected by the preferential purchase right to Buyer pursuant to a conveyance in the form of the Assignment effective as of the Effective Time, and the Purchase Price shall be increased by the amount the Purchase Price was reduced at Closing.

C.    Exclusion Adjustments. The Allocated Values of the Assets not conveyed to Buyer at Closing by reason of the application of Section 4.2B.3, Section 4.5, Section 4.6B, Section 4.7A, Section 4.7B.1, Section 4.9, Section 5.4C, Section 5.4D, and Section 5.5 will be referred to in this Agreement as the “Exclusion Adjustments,” provided that if any such Assets are later conveyed to the Buyer as provided in this Agreement, such Assets will no longer be an Excluded Asset, and the Purchase Price for the Final Settlement Statement will be increased by the Exclusion Adjustment for such Asset.

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D.    Exclusive Remedy. Except as otherwise provided in this Agreement, the remedies set forth in this Section 4.7 are the exclusive remedies under this Agreement related to the existence and exercise of preferential purchase rights and Required Consents to assign the Assets.

4.8    Rentals, Minimum Royalties, and Shut-in Royalties. Seller shall be responsible for the payment of all rental payments, minimum royalty payments, and shut-in royalty payments, or such other payments that are necessary, due, or may become necessary or due both before and after the Effective Time, and prior to the date that is sixty (60) days after the Closing Date, other than for those portions of the Assets for which the respective Operator is responsible to make such payments to the extent attributable to the period after the Effective Time, and Buyer agrees to remit its proportionate share of all such payments due after the Effective Time to Seller within thirty (30) days of receipt of invoice for same to the extent such payment is not included as an adjustment to the Purchase Price according to Section 2.4, Section 13.1A, or Section 13.1B.

4.9    Excluded Contracts. In the event that Buyer, prior to the Title Defect Date, discovers a Contract that (i) is not listed on Exhibit D, and (ii) will materially reduce the value to Buyer, or materially impair the use or operation, of the Assets affected by such Contract, Buyer, by written notice to Seller on or before the Title Defect Date, shall have the right to exclude such Contract and the Assets affected thereby from the Transaction, and reduce the Purchase Price by the Allocated Value of such affected Assets, whereupon such Contract and the Assets affected thereby shall be Excluded Assets. After Closing, Seller shall have the right, at its sole cost and expense, to attempt to obtain a termination, amendment or waiver of, or otherwise cure, to the reasonable satisfaction of Buyer, any Contract excluded by Buyer pursuant to this Section 4.9. In the event Seller is able to terminate, amend, waive or otherwise cure any such Contract to the reasonable satisfaction of Buyer on or before the Final Settlement Date, such Contract and the Assets affected thereby shall no longer be Excluded Assets, but shall be assigned to Buyer, using the form of Assignment attached hereto as Exhibit E, and the Purchase Price for the Final Settlement Statement will be increased by the Allocated Value of such Assets.

ARTICLE 5.

ENVIROMENTAL MATTERS

The provisions of this Article apply only to the environmental matters associated with the Assets as the result of oil and gas operations on the Lands.

5.1    Definitions. For the purposes of the Agreement, the following terms shall have the following meanings:

“Environmental Consultant” means a qualified employee of the Buyer or a third party consultant reasonably acceptable to Buyer and Seller.

“Environmental Defect” means (a) a condition in, on, or under an Asset (including, without limitation, air, land, soil, surface and subsurface strata, surface water and groundwater), or any circumstance, occurrence, act or omission that (i) causes an Asset to be in material violation of an Environmental Law or (ii) requires Remediation under an Environmental Law,

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and (b) the Environmental Defect Value of which exceeds Twelve Thousand Five Hundred Dollars ($12,500.00) per incident or condition (“Individual Environmental Threshold”). It is understood and agreed that matters of an essentially similar nature such as, but not limited to, oil spills, chemical barrels, or hazardous materials found at a single site shall be deemed a single incident or condition of an Environmental Defect. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other hazardous substances. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM, asbestos and other wastes or hazardous substances. NORM containing material and other wastes or hazardous substances may have come in contact with various environmental media, including, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, NORM and other hazardous substances from the Assets. The presence of NORM, asbestos-containing materials that are non-friable, Hydrocarbons or hazardous substances cannot be claimed as an Environmental Defect, except to the extent constituting a material violation of Environmental Laws.

“Environmental Defect Notice” means each written notice given by Buyer to Seller on or before the date that is six (6) calendar days prior to Closing, as may be extended pursuant to Section 12.1 (the “Environmental Defect Date”) alleging an Environmental Defect. To be effective, each Environmental Defect Notice must be in writing and must satisfy the following conditions precedent: (i) name the affected Asset; (ii) describe the condition that causes the Environmental Defect; (iii) provide reasonable factual substantiation for the Environmental Defect; and (iv) state the estimated Remediation cost as reasonably calculated by the Environmental Consultant. Buyer shall be deemed to have waived, and Seller shall have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by Seller on or before the Environmental Defect Date.

“Environmental Defect Value” means the reasonable costs to Remediate that particular Environmental Defect.

“Environmental Law” means any and all laws, as they exist on the date hereof, (whether common or statutory), compacts, treaties, conventions, rules, regulations, orders, decrees judgments, injunctions, promulgated or entered under such laws by any federal, state, tribal or local governmental entity relating to public or employee health and safety, pollution or protection of the environment including, without limitation, common law claims and theories of liability in negligence, trespass, nuisance, strict liability or any other common law theory, Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), the Superfund Amendments and Reauthorization Act of 1986, as amended (“SARA”), the Resource Conservation and Recovery Act, as amended (“RCRA”), the Federal Safe Drinking Water Act, the Federal Water Pollution Control Act, the Emergency Planning and Community Right-to-Know Act, the Clean Air Act, the Oil Pollution Act, the Hazardous and Solid Waste Amendments Acts of 1984, as amended, and the Toxic Substances Control Act, as

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amended, including the rules of the Occupational Safety and Health Act, as amended (“OSHA”) and/or the State of Wyoming, and any and all other federal, state, tribal and local laws, rules, regulations and orders relating to reclamation of land, wetlands and waterways or relating to use, storage, emissions, discharges, cleanup, releases or threatened releases of pollutants on or into the workplace or the environment (including, without limitation, ambient air, oceans, waterways, wetlands, surface water, groundwater (tributary and non-tributary), land surface or subsurface strata), or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transportation or handling of hazardous substances, and the production, handling, processing, distribution, use, treatment, storage, disposal injection, and transportation of oil and gas and all matters utilized, handled or produced in association, including salt water.

“Remediation,” “Remediate”or “Remediated” means actions taken to correct an Environmental Defect or otherwise required to remediate an Environmental Defect in compliance with applicable Environmental Law, as recommended in writing by the Environmental Consultant.

5.2    Environmental Assessment. Buyer may conduct an onsite inspection, environmental assessment and compliance audit of the Assets (“Environmental Assessment”) at Buyer’s cost and expense. Seller shall provide Buyer with all information in Seller’s possession or control, and shall use commercially reasonable efforts assist Buyer to obtain all information from the Operator, pertaining to the environmental condition of the Asset including, but not limited to, status of any environmental audits, permits, records and assessments, and shall make available to Buyer all present personnel employed by Seller who would reasonably be expected to have knowledge or information regarding the environmental status or condition of the Assets. Buyer shall provide Seller prior written notice of any environmental inspections and tests, including sampling activities and Buyer shall give Seller the opportunity to participate in all such inspections and tests. Upon Seller’s request, Buyer shall provide to Seller, at Seller’s reasonable expense, all reports of environmental inspections and tests, provided that all such reports shall be deemed to be confidential between the Parties and subject to the confidentiality provisions of Section 8.3A. Buyer’s obligations under the first and fourth sentences of this Section 5.2 will survive termination of this Agreement. In addition, Buyer will have the environmental inspection and access rights and obligations set forth in Section 3.3.

5.3    Environmental Representation and Warranty. Except for those matters identified on Schedule 5.3, (i) to Seller’s knowledge, the Assets are being operated in material compliance with all Environmental Laws, (ii) Seller, or to Seller’s knowledge, the respective Operator, has not received a written notice of a violation of any Environmental Law from a governmental authority with respect to the Assets, (iii) to Seller’s knowledge, no notice of action alleging a material violation of an Environmental Law is pending or threatened against the Assets, (iv)  there are no civil, criminal or administrative actions, lawsuits, litigation, hearing or proceeding against the Seller, or to Seller’s knowledge the respective Operator, with respect to the Assets as a result of the violation or breach of any Environmental Law. Identifying a matter on Schedule 5.3 shall not preclude a claim by Buyer that the matter identified on Schedule 5.3 is an Environmental Defect under this Agreement. With respect to any matter identified on Schedule 5.3, Seller shall provide Buyer, within three (3) business days of execution of this Agreement, a report providing all of the information (but only to the extent of information in the

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Records and Seller’s other files) required for Buyer to prepare an Environmental Defect Notice pursuant to this Agreement for each matter identified on Schedule 5.3.

5.4    Environmental Liabilities and Obligations.

A.    Assumed Environmental Liabilities. Subject to the provisions of Section 5.4C, Section 5.4D and Section 5.5, from and after Closing, Buyer agrees to assume and pay, perform, fulfill, discharge and release Seller from all Losses relating to environmental conditions in, on, or under the Assets attributable to the period of time before and after Closing including, without limitation, any and all liability for (i) groundwater contamination; (ii) NORM; (iii) man-made material fibers; (iv) the obligation to plug and abandon all of the wells located on the Lands and reclamation of existing well sites on the Lands, other than those wells identified on Schedule 6.17; and (v) Environmental Defects (disregarding, for this purpose, the Individual Environmental Threshold and the Aggregate Deductible) attributable to the period of time before and after the Closing (collectively, the “Assumed Environmental Liabilities”).

B.    Environmental Defect Notice. For those Environmental Defects, if any, to be alleged prior to Closing, Buyer shall give Seller written notice of any Environmental Defects pursuant to an Environmental Defect Notice delivered no later than the Environmental Defect Date.

C.    Defect Adjustments. Upon delivery of a timely Environmental Defect Notice, the Parties shall proceed as set forth in this Section 5.4. With respect to those Environmental Defects that are not contested by Seller, Seller shall elect one of the following options: (i) to Remediate, at Seller’s sole cost and expense, the Environmental Defect on the affected Assets as promptly as practicable prior to Closing, such Remediation to be consistent with Environmental Laws and to the reasonable satisfaction of Buyer; (ii) to attempt to Remediate, at Seller’s sole cost and expense, the specified Environmental Defect(s) consistent with Environmental Laws after Closing and to the reasonable satisfaction of Buyer, as provided in Section 5.4D; (iii) with Buyer’s consent, which may be withheld in its sole discretion, to reduce the Purchase Price by the Environmental Defect Value, in which event Buyer hereby releases Seller from any further obligations relating to the Environmental Defects for which the Purchase Price was reduced; or (iv) to retain the Asset affected by such Environmental Defect and reduce the Purchase Price by the Allocated Value of such affected Asset, in which case the affected Asset shall become an Excluded Asset. Notwithstanding anything in this Section 5.4C, there shall not be any adjustment to the Purchase Price or other remedies available to Buyer (i) for any Individual Environmental Defect for which the Environmental Defect Value does not exceed the Individual Environmental Threshold; and (ii) in no event shall there be any adjustment to the Purchase Price for Environmental Defects that exceed the Individual Environmental Threshold, except to the extent the Aggregate Deductible is exceeded, as provided in Section 4.2B.2.

D.    Post-Closing Remediation. If Seller elects to Remediate an Environmental Defect(s) post-Closing, the Asset affected by the Environmental Defect will be deemed to be an Excluded Asset and will be retained by Seller at Closing, and the Purchase Price will be reduced by the Allocated Value of the Asset affected by the Environmental Defect(s). If Seller Remediates the Environmental Defect(s) to Buyer’s reasonable satisfaction on or before the Final

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Settlement Due Date, Seller will convey the affected Asset to Buyer effective as of the Effective Time, and the Final Settlement Statement will be adjusted upwards by an amount equal to the reduction in the Purchase Price at Closing with respect to such Asset. If Seller does not Remediate the Environmental Defect(s) to Buyer’s reasonable satisfaction by the Final Settlement Statement Due Date, then unless (a) Seller and Buyer agree that the affected Assets will be conveyed to Buyer for an amount equal to the Allocated Value thereof less the Environmental Defect Value, subject to Section 4.2B.2, or such other amount as is agreed by the Parties, (b) Seller will retain the affected Asset and there will be no further downward adjustment to the Purchase Price, and such affected Asset shall become an Excluded Asset. If the Parties agree on alternative (a), Seller will convey the Asset affected by the Environmental Defect to Buyer effective as of the Effective Time, and the Final Settlement Statement will be adjusted by the amount agreed upon by the Parties with respect thereto. During the period of time from Closing to the Final Settlement Statement Due Date, Buyer agrees to afford Seller and its officers, employees, and other authorized representatives reasonable access, during normal business hours, to the Assets and all Records in Buyer’s or any of its affiliates’ possession in order to facilitate Seller’s attempt to cure such Environmental Defect(s).

5.5    Contested Environmental Defects. If Seller contests the existence of an Environmental Defect or the Environmental Defect Value, Seller shall notify Buyer in writing on or before four (4) calendar days after receipt of the Environmental Defect Notice (“Rejection Notice”). The Rejection Notice shall state with reasonable specificity the basis of the rejection of the Environmental Defect or the Environmental Defect Value. If Seller fails to timely deliver a Rejection Notice, Seller shall be deemed to have accepted the validity of the Environmental Defect and Buyer’s estimate of the Environmental Defect Value, and shall be deemed to have waived its own option to contest the Environmental Defect pursuant to Section 5.4 or this Section 5.5. Within one (1) calendar day of receipt of the Rejection Notice, representatives of Buyer and Seller knowledgeable in environmental matters shall meet and, either (i) mutually agree to reject the particular Environmental Defect; (ii) agree on the validity of such Environmental Defect and the Environmental Defect Value; or (iii) agree that the Asset affected by such Environmental Defect shall be retained by Seller and shall become an Excluded Asset. If the Parties cannot agree on any option in the preceding sentence, then disputed matters relating to the validity of a claimed Environmental Defect or Environmental Defect Value, whether an Environmental Defect has been Remediated to Buyer’s reasonable satisfaction or any other disputed environmental matters (“Environmental Disputed Matters”) will be determined by binding arbitration, with a single arbitrator mutually acceptable to Seller and Buyer who either is a reputable environmental consultant or is licensed to practice law in the State of Wyoming and who has at least ten (10) years of environmental consulting or environmental law experience (the “Environmental Arbitrator”). The arbitration will occur as soon as practicable but in any event within thirty (30) days following designation of the Environmental Arbitrator, and the Environmental Arbitrator shall issue a decision within ten (10) business days following completion of the arbitration. The Environmental Arbitrator’s determination shall be final and binding upon Seller and Buyer and enforceable in any court of competent jurisdiction. The fees charged by the Environmental Arbitrator shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. In the event that arbitration of any Environmental Disputed Matters is required and the arbitration is not completed by Closing, the affected Asset shall not be assigned to Buyer at Closing and the Purchase Price will be reduced by the Allocated Value of such affected Asset. Upon issuance of the Environmental Arbitrator’s decision, Seller, at Seller’s

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option, may either (i) with Buyer’s consent, which may be withheld in its sole discretion, assign to Buyer (in substantially the same form as the Assignment) the Asset affected by the Environmental Disputed Matter, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Environmental Defect Value of any Environmental Defect that has not been Remediated to Buyer’s reasonable satisfaction, subject to Section 4.2B.2 consistent with the Environmental Arbitrator’s decision, or (ii) retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

5.6    Exclusive Remedies. Except as otherwise provided in this Agreement, the rights and remedies granted each Party in this Article, including the rights of each Party to not close pursuant to Article 11.1C, are the exclusive rights and remedies against the other Party related to any Environmental Defect or other environmental matters.

ARTICLE 6.

SELLER'S REPRESENTATIONS AND WARRANTIES

Seller makes the following representations and warranties as of the execution of this Agreement and as of Closing:

6.1    Company Representations.

A.    Status and Authority. Seller is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Montana and is authorized to conduct business in Wyoming. Seller has all requisite power and authority to own the Assets, to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other document executed or to be executed by Seller in connection with the Transactions contemplated herein. The execution, delivery, and performance by Seller of this Agreement and each other document executed or to be executed by Seller in connection with the Transaction and the consummation by it of the Transaction have been duly authorized by all necessary limited liability company actions of Seller.

B.    No Violation. Assuming the receipt of all Required Consents, the execution and delivery of this Agreement and the consummation of the transactions contemplated hereby do not and will not: (i) create a lien or encumbrance on the Assets that will remain in existence after Closing; (ii) violate, or be in conflict with, any provision of Seller’s governing documents, (iii) violate or conflict with any provision of any statute, rule or regulation applicable to Seller or the Assets or any Material Contract, or (iv) violate, or be in conflict with, any judgment, decree or order applicable to Seller, except in the case of clauses (iii) and (iv) where such violation or conflict would not have a material effect upon the ability of Seller to consummate the Transaction and perform its obligations under this Agreement.

6.2    Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to this Transaction for which Buyer shall have any responsibility whatsoever.

6.3    No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, to the knowledge of Seller, threatened against Seller by any third party.

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6.4    Foreign Person. Seller is not a “foreign person” within the meaning of the Internal Revenue Code of 1986, as amended (the “Code”), Sections 1445 and 7701 (i.e., Seller is not a nonresident alien, foreign corporation, foreign partnership, foreign trust, or foreign estate as those terms are defined in the Code and any regulation promulgated thereunder).

6.5    Litigation. Except as set forth on Schedule 6.5, there are no suits, actions, arbitrations or other proceedings by or before any court, arbitrator or other governmental agency pending against Seller (or to Seller’s knowledge, the respective Operator) or, to Seller’s knowledge, threatened in writing against Seller or the respective Operator, which relate to (and could diminish the value of or impede the operation of) the Assets or the Transaction.

6.6    Judgments. Except as set forth on Schedule 6.6, there are no unsatisfied judgments or injunctions issued by a court of competent jurisdiction or other governmental agency outstanding against Seller (or to Seller’s knowledge, the respective Operator) that would be reasonably expected to materially interfere with the operation of any of the Assets, or materially affect the value of any of the Assets, or impair Seller’s ability to enter into this Agreement or consummate this Transaction.

6.7    Compliance with Law. To Seller’s knowledge, the Assets have been operated in material compliance with all applicable federal, state and local laws, rules, regulations and orders, excluding Environmental Laws, the Seller’s representations and warranties with respect to which are in Section 5.3, Seller (or to Seller’s knowledge, the respective Operator) has not received a notice of a violation of any statute, law, ordinance, regulation, permit, rule or order of any federal, state, tribal or local government or any other governmental department or agency, or any judgment, decree or order of any court, applicable to the Assets or operations of the Assets, which remains uncured.

6.8    Material Contracts. Exhibit D includes all of the contracts and agreements that are material to the ownership and operation of the Assets to which Seller is a party, or of which Seller has knowledge. To Seller’s knowledge, the Material Contracts are in full force and effect and constitute valid and binding obligations of the parties thereto. Seller is not in breach, violation or default (and no situation exists which with the passing of time or giving of notice would create a breach, violation, or default) of its obligations under the Material Contracts, and to Seller’s knowledge there is no breach, violation, or default under the Material Contracts by any third party (and no situation exists which with the passing of time of giving of notice would create a breach, violation, or default) exists.

6.9    Records. Subject to (y) the items excluded to arrive at the definition of Records, and (z) items which are Excluded Assets, Seller represents that: (i) all of the Records are files, or copies thereof, that Seller has used in the ordinary course of operating and owning the Assets; (ii) Seller has not intentionally withheld any material information from the Records; and (iii) Seller has not intentionally misrepresented any material information in the Records.

6.10    Property Expenses. In the ordinary course of business, (i) Seller has paid its share of all Property Expenses attributable to the period of time prior to the Effective Time as such Property Expenses become due, and (ii) such Property Expenses are being paid in a timely manner before the same become delinquent, except (y) such Property Expenses as are disputed in

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good faith by Seller in a timely manner and for which Seller shall retain responsibility, as set forth on Schedule 6.10(y), and (z) except such Property Expenses as have or will be taken into account as an adjustment to the Purchase Price under Section 2.4.

6.11    Capital Projects. Schedule 6.11 is a list and description of all wells or other specified capital projects, of which Seller has been made aware, to the extent such capital projects will extend beyond the Effective Time, and associated costs or estimates thereof to the extent such costs or estimates are reasonably estimated to exceed Fifty Thousand Dollars ($50,000.00) per well or project net to Seller’s interest (the “Capital Projects”). All costs and expenses incurred by the Parties with respect to the Capital Projects will be apportioned between the Parties as of the Effective Time, with Buyer assuming all post-Effective Time costs and expenses and Seller retaining all pre-Effective Time costs and expenses.

6.12    Leases. To Seller’s knowledge, all conditions necessary to keep each Lease in full force and effect in accordance with its terms have been performed and all material obligations under the Leases have been fully performed, including the proper and timely payment of all royalties, rentals, shut-in payments and other payments due under the Leases. To Seller’s knowledge, there are no currently pending requests or demands for payments, adjustments of payments or performance pursuant to obligations under the Leases. Seller (or to Seller’s knowledge, the respective Operator) has not received a written notice of default with respect to the payment or calculation of rentals and royalties attributable to the Assets.

6.13    Licenses and Permits. Seller (or to Seller’s knowledge, the respective Operator) has all governmental licenses, permits, authorizations, consents, and approvals required for the ownership of the Assets, and has materially complied with all applicable rules, regulations, and ordinances of any governmental authority having jurisdiction over the Assets and as to which non-compliance would have a material effect on the Assets or any of them.

6.14    Hydrocarbon Sales Contracts. Except under the Contracts, Seller (or to Seller’s knowledge, the respective Operator) has not (i) sold forward any Hydrocarbons or (ii) received any material advance, “take-or-pay” or other similar payments under production sales contracts that entitle the purchasers to “make up” or otherwise receive deliveries of Hydrocarbons without paying at such time the contract price therefor. To Seller’s knowledge, and except under the Contracts, no Hydrocarbons are subject to a sales contract (other than division orders or spot sales agreements terminable on no more than thirty (30) days’ notice) and no person has any call upon, option to purchase or similar rights with respect to the production from the Assets and the Assets are not bound by futures, hedge, swap, collar, put, call, floor, cap, option or other contracts that are intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, securities, foreign exchange rates or interest rates. Proceeds from the sale of oil, condensate, and gas from the Assets are being received in all respects by Seller in a timely manner and are not being held in suspense for any reason.

6.15    Imbalance Volumes. To Seller’s knowledge, except as identified on Schedule 6.15, as of the Effective Time and as of Closing, there will not exist any material imbalances (a) with any gatherers, processors, or transporters associated with the Assets where Seller has received a quantity of gas prior to the Effective Time for which Seller will have a duty

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after the Effective Time to deliver an equivalent quantity of gas or pay a sum of money, and (b) relating either to production from or at the wellhead between to co-tenant or working interest owners in a well, unit, or field which are associated with the Assets where Seller has received any quantity of gas prior to the Effective Time for which Buyer will have a duty after the Effective Time to deliver an equivalent quantity of gas or pay a sum of money.

6.16    Insurance. Seller maintains, and through the Closing Date will maintain, with respect to the Assets, the insurance coverage described on Schedule 6.16.

6.17    Plugging Obligations. To Seller’s knowledge, only the Wells listed on Schedule 6.17 are currently obligated by law or contract to be plugged and abandoned in compliance with all applicable requirements of regulatory authority having jurisdiction thereof.

6.18    Preferential Rights and Required Consents. Except as identified on Schedule 4.7 and for consents of federal and state agencies or authorities in connection with the assignment of any federal and state leases or interest therein, there are no preferential rights of purchase or consents to assign in favor of third parties with respect to the Assets.

6.19    Area of Mutual Interest, Tax Partnerships. Except as identified on Exhibit D or Schedule 6.19, no Asset is subject to (or has related to it) any area of mutual interest agreements or any farm-out or farm-in agreement under which any party thereto is entitled to receive assignments not yet made, or could earn additional interests in or assignments of all or any portion of the Assets after the Effective Time, or contain any drilling commitments that Buyer would be obligated to satisfy after the Effective Time. No Asset is owned by, subject to, or has related to it in any way, directly or indirectly, any tax partnership for federal, state or local tax purposes.

6.20    Taxes. All due and payable Taxes (as later defined) with respect to the Assets, which became due prior to the Closing Date for any periods prior to the Effective Time, have been properly paid, or if not due prior to the Closing Date for any periods prior to the Effective Time, adequate provision has been made for their payment. With respect to the Assets, there are no suits, actions, claims, investigations, audits, inquiries or proceedings pending, or to Seller’s knowledge threatened, against Seller in respect of Taxes. There are no tax liens burdening the Assets, except liens for current Taxes not yet due and payable and for which adequate provision has been made for their payment. Notwithstanding the foregoing, Seller’s representation and warranties under this Section 6.20 are limited to Seller’s knowledge with respect to any Taxes payable by the Operator.

6.21    Title. Seller warrants title to the Assets only as provided in the Assignment.

6.22    Surface Access. To Seller’s knowledge, there are no surface use or access agreements currently in force and effect that would materially interfere with oil and gas operations on the Leases.

6.23    Intellectual Property. There are no trademarks, trade names, patents, service marks, brand names, computer programs, databases, industrial designs, copyrights or other intangible property owned or licensed by Seller (the “Intellectual Property”), that are materially necessary for the operation, or continued operation of any Asset, or for the ownership and

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operation, or continued ownership and operation, of any Asset, except for the Intellectual Property which is a part of the Assets.

ARTICLE 7.

BUYER'S REPRESENTATIONS AND WARRANTIES

Buyer makes the following representations and warranties to Seller as of the execution of this Agreement and as of Closing:

7.1    Corporate Representations. Each Buyer makes the following representations and warranties with respect to itself:

A.    Status and Authority. Buyer is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is authorized to conduct business in Wyoming. Buyer has all requisite power and authority to own the Assets, to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other document executed or to be executed by Buyer in connection with the Transactions contemplated herein. The execution, delivery, and performance by Buyer of this Agreement and each other document executed or to be executed by Buyer in connection with the Transaction and the consummation by it of the Transaction have been duly authorized by all necessary company and/or corporate actions of Buyer.

B.    No Violation. The execution and delivery of this Agreement does not (i) violate or conflict with any provision of Buyer’s governing documents, or any provision of any statute, rule or regulation applicable to Buyer or any material lease, contract, agreement, instrument or obligation to which Buyer is a party or by which Buyer is bound or (ii) violate or conflict with any judgment, decree or order applicable to Buyer.

7.2    Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to this Transaction for which Seller shall have any responsibility whatsoever.

7.3    Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or governmental body pending or, to Buyer’s knowledge, threatened in writing against it before any governmental authority that impedes or is likely to impede Buyer’s ability to consummate this Transaction and to assume the liabilities to be assumed by Buyer under this Agreement, including without limitation, the Assumed Liabilities.

7.4    Financing. As of Closing, Buyer has the financial resources available to close this Transaction without financing that is subject to any contingency and to fund the obligations required by this Agreement.

7.5    Consents. There are no consents, including requirements for consents from third parties, in each case, that Buyer is required to obtain in connection with its acquisition and ownership of the Assets as contemplated by this Agreement.

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7.6    Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened in writing against Buyer or any affiliate of Buyer.

7.7    Regulatory. Buyer is and hereafter shall continue to be qualified to own and assume operatorship of the Assets in the jurisdiction where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator.

7.8    Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any state blue sky laws or any other securities Laws.

7.9    Independent Evaluation. Buyer is experienced and knowledgeable in the oil and gas business and is aware of its risks. Buyer has been afforded the opportunity to examine the Records, and materials made available to it by Seller with respect to the Assets (the “Background Materials”). The Background Materials include files, or copies thereof, that Seller has used in its normal course of business and other information about the Assets that Seller has compiled or generated.

ARTICLE 8.

COVENANTS AND AGREEMENTS

8.1    Covenants and Agreements of Seller. Seller covenants and agrees with Buyer as follows:

A.    Operations and Status Prior to Closing. From the date of execution hereof to the Closing, Seller will maintain (and shall use commercially reasonable efforts to cause the Operator to maintain) the Assets in a manner consistent with its past practices. Seller agrees to maintain the insurance that it now has in effect with respect to the Assets through the date of Closing. From the date of execution of this Agreement to the Closing Date, Seller shall pay or cause to be paid its share of all Property Expenses incurred in connection with the ownership or operation of the Assets, subject to adjustment to the Purchase Price pursuant to Section 2.4 and shall maintain the insurance described in Schedule 6.16. Seller shall maintain its limited liability company status from the date hereof until Closing to assure that as of the Closing Date, Seller will not be under any material, legal or contractual restriction that would prohibit or delay the timely consummation of this Transaction.

B.    Restriction on Operations. Except (x) for operations covered by Capital Projects, (y) for actions taken in connection with emergency situations or to maintain a Lease that is otherwise about to expire, and (z) as expressly contemplated by this Agreement, unless Seller obtains the prior written consent of Buyer to act otherwise, from the date of execution of this Agreement to the Closing Seller shall not (i) propose or approve any operations on the Assets anticipated to cost, net to the Seller’s interest, more than Fifty Thousand Dollars ($50,000.00) per activity, (ii) convey or dispose of any part of the Assets (other than replacement

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of equipment or sale of Hydrocarbons or obsolete equipment in the regular course of business); (iii) enter into any new farmout, farmin or other similar contract affecting the Assets, (iv) enter into any new contracts affecting the Assets with obligations in excess of thirty (30) days other than such new contracts which are terminable on not more than thirty (30) days’ notice; (v) abandon any Well or release (or permit to terminate), or modify its rights under all or any portion of the Leases; (vi) modify or terminate any Material Contract; and (vii) respond to any, or fail to respond, to any notices of forced pooling or spacing applications pertaining to Leases or Lands without providing a copy of said notice to Buyer and allowing Buyer to determine how to respond to said notice on behalf of Seller. Buyer acknowledges that Seller owns undivided interests in the Assets that the Seller is not the operator thereof, and Buyer agrees that the acts or omissions of the other working interest owners (including the Operators) shall not constitute a breach of the provisions of this Section 8.1B, and no action required of other working interest owners shall constitute a breach of this Section 8.1B, so long as Seller has voted its interest in a manner that complies with the provisions of this Section 8.1B.

C.    Operatorship. In the event any Operator resigns or is deemed to have resigned as operator of any of the Assets pursuant to the terms of the applicable joint operating agreement pertaining to such Assets, Seller shall vote solely for itself, pursuant to the terms of the applicable joint operating agreement, to succeed as operator of such Assets. This obligation shall survive Closing with respect to any Assets not conveyed to Buyer at Closing by reason of the application of Section 4.2B.3, Section 4.5, Section 4.6B, Section 4.7A, Section 4.7B.1, Section 5.4C, Section 5.4D or Section 5.5, until such Assets are conveyed to Buyer or conclusively determined to be Excluded Assets.

D.    Notification of Claims. Seller shall promptly notify Buyer of any suit, action or other proceeding before any court or governmental agency and any cause of action that relates to the Assets or that might result in impairment or loss of Seller’s title to any portion of the Assets or the value thereof or that might hinder or impede the operation of the Leases arising or threatened prior to the Closing.

8.2    Covenants and Agreements of Buyer. Buyer covenants and agrees with Seller that Buyer shall maintain its limited liability company status from the date hereof until the Closing Date and use all reasonable efforts to assure that as of the Closing Date it will not be under any material, legal or contractual restriction that would prohibit or delay the timely consummation of this Transaction.

8.3    Covenants and Agreements of the Parties. The Parties covenant and agree as follows:

A.    Confidentiality. Subject to Section 15.6, all data and information, whether written or oral, obtained from either Party in connection with this Transaction, including the Records, whether obtained by either Party before or after the execution of this Agreement, data and information generated by either Party in connection with this Transaction, and all information regarding the existence of this Transaction (collectively, the “Information”), is deemed by the Parties to be confidential and proprietary of the Parties. Until the Closing and for a one (1) year period after the Closing, except as required by law or applicable stock exchange rule, the Parties and its officers, agents and representatives will hold in strict confidence the

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terms of this Agreement, and all Information, except any Information which: (i) at the time of disclosure to one Party by the other Party is in the public domain; (ii) after disclosure to one Party by the other Party becomes part of the public domain by publication or otherwise, except by breach of this commitment by either Party; (iii) the Parties can establish by competent proof was rightfully in the other Party’s possession at the time of disclosure; (iv) either Party rightfully receives from third parties free of any obligation of confidence; (v) is developed independently by either Party without the Information, provided that the person or persons developing the data shall not have had access to the Information, (vi) is disclosed to a Party’s attorneys, accountants, lending institutions, members and shareholders, subject to the same confidentiality restrictions as are set forth in this Section 8.3A, or (vii) the relevant details regarding the Transaction are disclosed to third parties in order to obtain Required Consents, or the relevant parts of this Agreement are disclosed to third parties to deal with preferential rights to purchase under Section 4.7B. In the event the Closing does not occur, the Parties will be bound by the terms and conditions of that certain Confidentiality Agreement dated August 7, 2013.

B.    Return of Confidential Information. If this Transaction does not close on or before Closing, or such later date as agreed to by the Parties, Buyer shall (i) return to Seller all copies of the Confidential Information in possession of Buyer obtained pursuant to any provision of this Agreement; (ii) destroy any and all notes, reports, studies or analyses based on or incorporating the Confidential Information. The terms of Section 8.3A, Section 8.3B, and Section 8.3C shall survive termination of this Agreement.

C.    Injunctive Relief. Buyer and Seller agree that they will not have an adequate remedy at law if the other Party violates any of the terms of Sections 8.3A and/or Section 8.3B. In such event, the non-breaching Party will have the right, in addition to any other it may have, to obtain injunctive relief to restrain any breach or threatened breach of the terms of Sections 8.3A and/or Section 8.3B, or to obtain specific enforcement of such terms.

D.    Notice of and Cure Period for Breach. If, prior to Closing, either Seller or Buyer develops or possesses information that leads it to believe that the other Party may have breached a representation, warranty or covenant under this Agreement that Party shall promptly notify the other Party of such potential breach. Any breach of this Agreement may be cured within 48 hours after the notification, exclusive of weekends and holidays, of receipt of written notice of such breach. Notwithstanding the foregoing, this Article shall not apply to breach of the Parties’ obligations at and after Closing and shall not operate to delay Closing.

E.    Notice of Material Adverse Effect. If, prior to Closing, either Seller or Buyer develops, receives or possesses information of a potential Material Adverse Effect not known by or previously disclosed to the other Party, such Party shall promptly notify the other Party of such potential Material Adverse Effect. As used in this Agreement, “Material Adverse Effect” shall mean any state of facts, change, event, effect or occurrence (when taken together with all other states of fact, changes, events, effects or occurrences), that is (i) materially adverse to the ownership, use, operations or value of the Assets, as a whole, or (ii) materially adverse to the ability of the Parties to consummate the transactions contemplated by this Agreement in a timely manner. Notwithstanding the foregoing, the following shall not be considered a Material Adverse Effect: (a) national or international business, economic or political conditions; (b) events affecting the financial, banking or securities markets; (c) conditions (or changes in

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such conditions) generally affecting the oil and gas industry; (d) increases in energy, electricity, natural gas, oil, or other raw materials or operating costs; (e) changes in generally accepted accounting principles or Law; (f) any event of force majeure; (g) changes in oil or natural gas prices, including changes in price differentials; or (h) acts of terrorism, sabotage, or war, whether declared or undeclared.

8.4    Suspense Accounts and Division of Interest. Seller has identified, listed, and scheduled the amount of all revenues or royalties currently held in suspense by Seller related to the Assets along with a brief description of the justification for the suspension in Schedule 8.4. At the Closing, Seller will provide to Buyer: (i) information regarding all of Seller’s accounts holding moneys in suspense together with a written explanation (as contained in Seller’s files) of why such moneys are held in suspense or other information identifying the proper disposition of such moneys and (ii) Seller’s division of interest and all supporting documentation regarding those royalty owners and working interest owners in the Leases for whom Seller disburses proceeds of production, together with all accounts holding funds payable to such third parties. From after Closing, Buyer agrees to pay and perform all of Seller’s obligations with respect to the suspense accounts listed on Schedule 8.4.

8.5    Record Retention. Seller may retain copies of all of the Records. For so long as Buyer owns an interest in the Assets, Buyer shall (a) retain the Records, (b) provide each Seller, its affiliates and its respective officers, employees and representatives with access to the Records during normal business hours for review and copying at Seller’s expense and (c) provide Seller, its affiliates and its respective officers, employees and representatives with access, during normal business hours, to materials received or produced after Closing relating to any indemnity claim made under Article 14 for review and copying at Seller’s expense.

8.6    Disclaimers.

A.    EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT OR THE ASSIGNMENT, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF THEIR AFFILIATES).

B.    EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN THIS AGREEMENT OR THE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR

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SEISMIC DATA OR INTERPRETATION RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES TO BE GENERATED BY THE ASSETS, (V) THE PRODUCTION OF OR ABILITY TO PRODUCE HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR RESPECTIVE EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN THIS AGREEMENT, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, OR ANY CLAIM BY BUYER FOR DAMAGES OR DEFECTS, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

C.    EXCEPT AS TO THE LIMITED EXTENT REPRESENTED OTHERWISE IN SECTION 5.3, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

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D.    SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 8.6 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY LAW.

ARTICLE 9.

TAX MATTERS

9.1    Definitions. For the purposes of this Agreement:

A.    “Asset Taxes” means all Property Taxes and Severance Taxes.

B.    “Income Taxes” means all Taxes based upon, measured by, or calculated with respect to (a) gross or net income or gross or net receipts or profits (including, but not limited to, franchise Tax and any capital gains, alternative minimum Taxes, net worth and any Taxes on items of Tax preference, but not including sales, use, goods and services, real or personal property transfer or other similar Taxes), (b) multiple bases (including, but not limited to, corporate franchise, doing business or occupation Taxes) if one or more of the bases upon which such Tax may be based upon, measured by, or calculated with respect to, is described in clause (a) above, or (c) withholding Taxes measured with reference to or as a substitute for any Tax described in clauses (a) or (b) above, and (d) and any penalties, additions to Tax, and interest levied or assessed with respect to a Tax described in (a), (b), or (c).

C.    “Property Taxes” means all ad valorem, real property, personal property, and all other Taxes and similar obligations, and any penalties, additions to Tax, and interest levied or assessed thereon, assessed against the Assets or based upon or measured by the ownership of the Assets, but not including Income Taxes, Severance Taxes, or Transfer Taxes.

D.    “Severance Taxes” means all extraction, production, excise, net proceeds, severance, windfall profit and all other Taxes and similar obligations, and any penalties, additions to Tax, and interest levied or assessed thereon, with respect to the Assets that are based upon or measured by the production of Hydrocarbons or the receipt of proceeds therefrom, but not including Property Taxes, Income Taxes, and Transfer Taxes.

E.    “Tax” or “Taxes” means any and all taxes, including any interest, penalties or other additions to tax, that may become payable in respect thereof, imposed by any governmental authority, which taxes shall include all income taxes, profits taxes, taxes on gains, alternative minimum taxes, estimated taxes, payroll taxes, employee withholding taxes, unemployment insurance taxes, social security taxes, welfare taxes, disability taxes, severance taxes, license charges, taxes on stock, sales taxes, harmonized sales taxes, use taxes, ad valorem taxes, value added taxes, excise taxes, goods and services taxes, franchise taxes, gross receipts taxes, occupation taxes, real or personal property taxes, land transfer taxes, stamp taxes, environmental taxes, transfer taxes, workers’ compensation taxes, windfall taxes, net worth taxes, and other taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges of the same or of a similar nature to any of the foregoing.

F.    “Transfer Taxes” means any and all transfer Taxes (excluding Income Taxes, Severance Taxes and Property Taxes), including sales, use, excise, goods and services,

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stock, conveyance, gross receipts, registration, business and occupation, securities transactions, real estate, land transfer, stamp, documentary, notarial, filing, recording, Permit, license, authorization and similar Taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges.

9.2    Apportionment of Property Taxes.

A.    The Parties acknowledge that the Converse County, Wyoming Property Taxes assessed with respect to certain of the Assets are measured by the production of Hydrocarbons (“Oil and Gas Property Taxes”). Oil and Gas Property Taxes shall be apportioned between the Parties in accordance with the relative ownership periods pre- and post-Effective Times. 2013 Oil and Gas Property Taxes, based on the value of 2013 production of Hydrocarbons and payable in 2014, shall be allocated between the Seller and Buyer in accordance with their proportionate ownership periods during 2013 before and after the Effective Time. For the purpose of calculating the Closing Amount under Section 2.4 and the Final Purchase Price under Section 13.1, 2013 Oil and Gas Property Taxes, which are determined by 2013 production and are payable in 2014 shall be estimated based on the then-current mill levies and the production occurring prior to the Effective Date with the resulting Purchase Price adjustment under Section 13.1 to be considered full and final settlement of all such Oil and Gas Property Taxes without regard to the actual Tax rates or assessments; provided that, if the actual amounts of such production and mill levies are not known at the time of the Closing, the amounts shall be re-estimated based on the best information available at the time of the Final Settlement Statement, and such estimated amounts shall thereupon become full and final settlement of such Oil and Gas Property Taxes for purposes of this Agreement.

B.    Property Taxes other than those described in clause A (“Other Property Taxes”) shall be deemed attributable to the period during which ownership of the applicable Assets gives rise to liability for such Other Property Taxes, and liability therefor allocated to Seller for all periods ending prior to the Effective Time and to Buyer for all periods beginning on or after the Effective Time. To the extent the actual amount of an Other Property Tax that is attributable to a period ending prior to the Effective Time (but not due and payable prior to the Closing) is not determinable at the time an adjustment to the Purchase Price is to be made with respect to such Other Property Tax pursuant to Section 2.4 and/or Section 13.1, as applicable, the Parties shall utilize the most recent information available in estimating the amount of such Other Property Tax for purposes of such adjustment, and the amount of such Other Property Tax used for purposes of Section 13.1 shall be considered full and final settlement of such Other Property Tax without regard to the actual Tax rates or assessments.

C.    Buyer shall be entitled to all rights to any refunds of Property Taxes allocable to Buyer pursuant to this Section 9.2 regardless of when received. Seller shall be entitled to all rights to any refunds of Property Taxes allocated to Seller pursuant to this Section 9.2. After Closing, Buyer shall timely file or cause to be filed all Tax Returns for Property Taxes required to be filed after the Closing and shall timely pay or cause to be paid to the taxing authorities all Property Taxes that become due and payable after the Closing. Any penalty, addition to Tax, or interest levied or assessed with respect to any Property Tax shall be allocated to, and shall be payable by, the Party to which the Tax to which such penalty, addition to Tax or interest relates is allocated, regardless of when such penalty, addition to Tax, or interest is levied

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or assessed; provided, however, that the liability for any penalty, addition to Tax, or interest levied or assessed with respect to any failure of Buyer to comply with the previous sentence shall be allocated to, and shall be payable by, Buyer.

9.3    Apportionment of Severance Taxes. Severance Taxes shall be deemed attributable to the period during which the production of the Hydrocarbons with respect to such Severance Taxes occurred, and liability therefor shall be allocated to Seller for pre-Effective Time Severance Taxes and to Buyer for post-Effective Time Severance Taxes. For the purpose of calculating the Closing Amount under Section 2.4 and the Final Purchase Price under Section 13.1, Severance Taxes for which the actual liability amount is not known as of such time shall be estimated based on current Wyoming Severance Tax rates, with the resulting Purchase Price adjustment under Section 13.1 to be considered full and final settlement of all such Taxes without regard to the actual Tax rates or assessments; provided that, if the actual amounts of the applicable Severance Tax rates are not known at the time of the Closing, the amounts shall be re-estimated based on the best information available at the time of the Final Closing Statement, and such estimated amounts shall thereupon become full and final settlement of such Severance Taxes for purposes of this Agreement. Buyer shall be entitled to all rights to any refunds of Severance Taxes allocable to Buyer pursuant to this Section 9.3 regardless of when received. Seller shall be entitled to all rights to any refunds of Severance Taxes allocated to Seller pursuant to this Section 9.3. After Closing, Buyer shall timely file or cause to be filed all Tax Returns for Severance Taxes required to be filed after the Closing and shall timely pay or cause to be paid to the taxing authorities all Severance Taxes that become due and payable after the Closing. Any penalty, addition to Tax, or interest levied or assessed with respect to any Severance Tax shall be allocated to, and shall be payable by, the Party to which the Tax to which such penalty, addition to Tax or interest relates is allocated, regardless of when such penalty, addition to Tax, or interest is levied or assessed; provided, however, that the liability for any penalty, addition to Tax, or interest levied or assessed with respect to any failure of Buyer to comply with the previous sentence shall be allocated to, and shall be payable by, Buyer.

9.4    Income Taxes. Each Party shall be responsible for its own Income Taxes.

9.5    Transfer Taxes. Buyer shall be liable for and shall indemnify the Seller Indemnified Parties for, any Transfer Taxes (including any related interest, penalties or legal costs) that may be imposed on any transfer of the Assets pursuant to this Agreement. If required by applicable law, Seller shall, in accordance with applicable law, calculate and remit any Transfer Taxes that are required to be paid as a result of the transfer of the Assets to Buyer and Buyer shall promptly reimburse Seller therefor. If Seller receives notice that any Transfer Taxes are due, Seller shall promptly forward such notice to Buyer for handling.

9.6    Post-Closing Tax Matters. After the Closing, each of Buyer and Seller shall:

A.    reasonably cooperate and assist the other (i) in preparing any Tax Returns relating to any Tax the Assets or imposed, or the Transaction, and (ii) in qualifying for any exemption or reduction in Tax that may be available;

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B.    reasonably cooperate in preparing for any audits, examinations or other tax proceedings by, or disputes with, taxing authorities regarding any Tax relating to the Assets or the Transaction;

C.    make available to the other, and to any taxing authority as reasonably requested, any information, records, and documents relating to a Tax incurred or imposed in connection with the Assets or the Transaction;

D.    provide timely notice to the other in writing of any pending or threatened Tax audit, examination, or assessment that could reasonably be expected to affect the other’s Tax liability under applicable law or this Agreement (a “Tax Controversy”), and to promptly furnish the other with copies of all correspondence with respect to any Tax Controversy; and

E.    allow the other to participate, at its own expense, in any Tax Controversy, and not settle any Tax Controversy without the prior written consent of the other, which may not be unreasonably withheld, conditioned or delayed.

9.7    Allocations for Federal Income Tax Purposes. Buyer and Seller acknowledge that, under Section 1060 of the Code, Buyer and Seller must report information regarding the allocation of the Purchase Price and any other amounts treated as consideration for federal income tax purposes (collectively, the “Allocation Amount”) to the United States Secretary of Treasury by attaching Department of Treasury, Internal Revenue Service, Form 8594 to their federal income tax returns for the tax period which includes the Closing Date. Buyer and Seller agree that the “Allocation Amount” shall be allocated among the Assets for Tax purposes in accordance with an allocation schedule that will be prepared and mutually agreed upon by the Parties prior to the Final Settlement Date (the “Tax Allocation Schedule”), in a manner consistent with Section 1060 of the Code to take into account any adjustments to the Purchase Price pursuant to this Agreement, including any indemnification payments pursuant to Article 14. Buyer and Seller shall each prepare their respective Forms 8594 with respect to transactions contemplated by this Agreement in a manner consistent with the Tax Allocation Schedule. The Parties shall not take any income tax position (whether in audits, on tax returns, or otherwise) that is inconsistent with such allocation unless required to do so by applicable law. Any dispute regarding the Tax Allocation Schedule will be determined by the Accounting Arbitrator pursuant to Section 13.1B.

ARTICLE 10.

CONDITIONS PRECEDENT TO CLOSING

10.1    Seller’s Conditions Precedent. The obligations of Seller at the Closing are subject, at the option of Seller, to the satisfaction or waiver at or prior to the Closing of the following conditions precedent:

A.    All representations and warranties of Buyer contained in this Agreement are true in all material respects (for this purpose any materiality qualifier in such representations and warranties will be ignored) at and as of the Closing in accordance with their terms as if such representations and warranties were remade at and as of the Closing, other than for representations and warranties that refer to a specified date, which need only be true on and as of

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the specified date. Buyer has performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing in all material respects;

B.    No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits this Transaction and that remains in effect at the time of Closing;

C.    Union Bank, N.A. shall have consented to the Transaction and shall have released any liens it may hold against the Assets;

D.    Helis Oil & Gas Company, L.L.C. (“Helis”) and Samson Resources Corporation (“Samson”) shall have consented to the Seller’s assignment to Buyer of that certain Leasehold Purchase and Exploration Agreement dated November 1, 2009 by and between Seller, Maurice W. Brown, and Helis, as amended from time to time (as so amended, the “Helis Agreement”); and

E.    No Material Adverse Effect shall have occurred and still be outstanding.

10.2    Buyer’s Conditions Precedent. The obligations of Buyer at the Closing are subject, at the option of Buyer, to the satisfaction or waiver at or prior to the Closing of the following conditions precedent:

A.    All representations and warranties of Seller contained in this Agreement are true in all material respects (for this purpose any materiality qualifier in such representations and warranties will be ignored) at and as of the Closing in accordance with their terms as if such representations and warranties were remade at and as of the Closing, other than for representations and warranties that refer to a specified date, which need only be true on and as of the specified date. Seller has performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Seller at or prior to the Closing in all material respects;

B.    No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits this Transaction and that remains in effect at the time of Closing;

C.    Except as provided in Section 4.7, Seller has delivered to Buyer all Required Consents other than any required governmental approvals that are the type of Required Consent ordinarily obtained post-Closing;

D.    Union Bank, N.A. shall have consented to the Transaction and shall have released any liens it may hold against the Assets; and

E.    Helis and Samson shall have consented to the assignment of the Helis Agreement.

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F.    Maurice W. Brown Oil & Gas, LLC shall be ready, willing and able to Close under that certain Purchase and Sale Agreement entered into contemporaneously herewith, by and between Maurice W. Brown Oil & Gas, LLC, as seller, and Buyer.

G.    No Material Adverse Effect shall have occurred and still be outstanding.

ARTICLE 11.

TERMINATION

11.1    Termination. This Agreement may be terminated in accordance with the following provisions:

A.    by Seller, at Seller’s option, if any of the conditions set forth in Section 10.1 have not been satisfied on or before March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), through no fault of Seller or are not waived by Seller, as of March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), provided that in the case of a failure of only the condition under Section 10.1A, the condition remains unsatisfied for five (5) business days following written notice thereof from Seller to Buyer specifying the reason such condition is unsatisfied (including any breach by Buyer of this Agreement);

B.    by Buyer, at Buyer’s option, if any of the conditions set forth in Section 10.2 have not been satisfied on or before March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), through no fault of Buyer, or are not waived by Buyer, as of March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), provided that in the case of a failure of only the condition under Section 10.2A, the condition remains unsatisfied for five (5) business days following written notice thereof from Buyer to Seller specifying the reason such condition is unsatisfied (including any breach by Seller of this Agreement);

C.    by Buyer or Seller, upon notice to the other given prior to Closing, if the aggregate of the Title and Environmental Defects Adjustment and the Exclusion Adjustments exceed ten percent (10%) of the Purchase Price;

D.    by either Party if Closing shall not have occurred on or before May 6, 2014; or

E.    upon the Parties’ mutual agreement;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to Paragraph A through D above if such Party is at such time in material breach of any provision of this Agreement. Except as provided in Section 11.2A, if a Party has rightfully terminated this Agreement, then the Deposit shall be promptly returned to Buyer, but in any event, within three (3) business days of such termination.

11.2    Remedies.

A.    Buyer’s Breach. If Closing does not occur because Buyer wrongfully fails to tender performance at Closing or otherwise is in material breach of this Agreement prior to Closing, and Seller is not in material breach of this Agreement and is ready and otherwise able to

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close, Seller shall retain the Deposit, and Seller may terminate this Agreement and keep the Deposit, which shall constitute liquidated damages hereunder, and which remedy shall be the sole and exclusive remedy available to Seller for any such failure of Buyer. The Parties acknowledge that (i) Seller’s actual damages upon such termination are difficult to ascertain, (ii) the liquidate damages set forth in the proceeding sentence is a reasonable estimate by the Parties of such actual damages to Seller, and (iii) such liquidated damages do not constitute a penalty. Buyer’s failure to tender performance at Closing shall not be considered wrongful if all of the conditions set forth in Section 10.2 have not been satisfied.

B.    Seller’s Breach. If Closing does not occur because Seller wrongfully fails to tender performance at Closing or otherwise is in material breach of this Agreement prior to Closing, and Buyer is not in material breach of this Agreement and is ready and otherwise able to close, Seller shall return the Deposit within three (3) business days, and Buyer may terminate this Agreement or pursue all legal and equitable remedies for Seller’s breach of this Agreement and Seller’s wrongful failure to close (excluding special, consequential, punitive or exemplary damages or loss of profits), including an action for specific performance. Seller’s failure to tender performance at Closing shall not be considered wrongful if all of the conditions set forth in Section 10.1 have not been satisfied.

C.    Effect of Termination. If this Agreement is terminated as provided in Section 11.1 or Section 11.2, then this Agreement shall be of no further force and effect and the Parties have no liability or obligation under this Agreement except for (i) the provisions of this Agreement which expressly survive termination of this Agreement, and (ii) the provisions of this Agreement relating to the retention or return of the Deposit, Section 6.2, Section 7.2, Section 8.3A, Section 8.3B, Section 8.3C, Section 14.14, Article 15, and such defined terms as set forth in this Agreement to give context to the provisions of this Agreement which survive termination under this Section 11.2C, all of which shall continue in full force and effect.

ARTICLE 12.

CLOSING

12.1    Date of Closing. The “Closing” of this Transaction shall be held on March 6, 2014, at 10:00 a.m. or such other date and time selected by mutual agreement of the Parties in writing. Upon execution of this Agreement, Buyer shall immediately commence its due diligence with respect to the environmental condition of the Assets, pursuant to Section 3.3 and Section 5.2, and shall use commercially reasonable efforts to complete such environmental due diligence prior to February 28, 2014. In the event that Buyer, despite its commercially reasonable efforts, due to snow cover or other adverse weather conditions, is unable to complete its onsite inspections or environmental assessments of the Assets (the uncompleted portion referred to as the “Outstanding Environmental Diligence”) on or before February 28, 2014, Buyer may, in its sole discretion, by written notice to Seller delivered on or before February 28, 2014 (an “Extension Notice”), elect to extend Closing to the date set forth in the Extension Notice, but in no event later than May 6, 2014. At the time Seller delivers the Extension Notice, Buyer will deliver to Seller a list of the Outstanding Environmental Diligence. In the event Buyer elects to extend Closing as set forth in the preceding sentence, Buyer shall use commercially reasonable efforts to complete the Outstanding Environmental Diligence and close as soon as possible, but in any event, on or before May 6, 2014. If Buyer has so elected to

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extend the Closing, Closing will take place on the tenth (10th) business day after Buyer has completed the Outstanding Environmental Diligence, but in no event later than May 6, 2014. The date the Closing actually occurs is called the “Closing Date”.

12.2    Place of Closing. The Closing shall be held at Buyer’s office in Denver, Colorado, or at such other place as Buyer and Seller may agree in writing.

12.3    Closing Obligations. At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

A.    Seller shall execute, acknowledge and deliver to Buyer (a) an Assignment, Bill of Sale, and Conveyance in the form attached as Exhibit E (the “Assignment”) conveying the Assets to Buyer as of the Effective Time, and (b) such other assignments or transfers necessary to convey the Assets to Buyer, including without limitation, any conveyances on official forms and related documentation necessary to transfer the Assets to Buyer in accordance with governmental regulation;

B.    Buyer shall deliver the Closing Amount to the account at the bank designated by Seller in the Preliminary Settlement Statement or other notice by wire transfer in immediately available funds, or by such other method as agreed to by the Parties;

C.    Seller shall execute and deliver to Buyer an affidavit of non-foreign status and no requirement for withholding under Section 1445 of the Code in the form attached as Exhibit F.

D.    Seller shall execute and deliver to Buyer an Officer’s Certificate, dated as of the Closing Date, in form and substance as set forth in Exhibit G;

E.    Buyer shall execute and deliver to Seller an Officer’s Certificate, dated as of the Closing Date, in form and substance as set forth in Exhibit H;

F.    Seller shall deliver the Records to Buyer, at Buyer’s expense, at Buyer’s Denver, Colorado offices within ten (10) business days after the Closing;

G.    Seller shall deliver to Buyer all Required Consents obtained as of Closing other than required governmental approvals ordinarily obtained post-Closing;

H.    Seller shall deliver and Seller and Buyer shall execute and deliver letters in lieu of transfer orders; and

I.    Seller and Buyer shall take such other actions and deliver such other documents as are contemplated by this Agreement.

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ARTICLE 13.

POST-CLOSING OBLIGATIONS

13.1    Final Settlement Statement.

A.    On or before one hundred and twenty (120) days after the Closing Date (“Final Settlement Statement Due Date”), Seller will prepare and deliver to Buyer a “Final Settlement Statement” setting forth each adjustment or payment that was not finally determined as of the Closing, and showing the calculation of such adjustment and the resulting final purchase price (the “Final Purchase Price”). On or before thirty (30) days after receipt of Seller’s proposed Final Settlement Statement, Buyer shall deliver to Seller a written report containing Buyer’s proposed changes to the Final Settlement Statement. Buyer’s failure to deliver to Seller a written report detailing proposed changes to the Final Settlement Statement by that date shall be deemed an acceptance by Buyer of the Final Settlement Statement as submitted by Seller. The Parties shall attempt to agree with respect to the changes proposed by Buyer, no later than five (5) days after receipt of Buyer’s suggested changes to the Final Settlement Statement (the “Dispute Resolution Date”). If the Parties are unable to agree Section 13.1B will apply. The date upon which such agreement is reached or upon which the Final Purchase Price is established, as provided in Section 13.1B, shall be herein called the “Final Settlement Date.” If the Final Purchase Price is more or less than the sum of the Closing Amount plus the Deposit, Buyer or Seller shall make the appropriate payments by wire transfer in same day funds to the appropriate Party, without interest, within ten (10) days of the Final Settlement Date.

B.    If Seller and Buyer are unable to resolve the matters with respect to Buyer’s proposed changes by the Dispute Resolution Date, each of Buyer and Seller shall within ten (10) business days after the Dispute Resolution Date, summarize its position with regard to such dispute in a written document of twenty (20) pages or less and submit such summaries to such person as the Parties may mutually select (the “Accounting Arbitrator”), together with Buyer’s proposed changes, the Final Settlement Statement and any other documentation such Party may desire to submit. Within ten (10) business days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and enforceable against any of the Parties in any court of competent jurisdiction. The costs of the Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller. If the parties are unable to agree upon the Accounting Arbitrator within ten (10) business days after the Dispute Resolution Date, then either Party may apply to the Eighth Judicial District Court in and for Converse County, Wyoming for the appointment of an arbitrator pursuant to the Wyoming Uniform Arbitration Act, Wyo. Stat. § 1-36-101, et seq.

C.    If after the delivery of the Final Settlement Statement pursuant to the provisions of Section 13.1A (i) either Party receives monies (including proceeds of production) belonging to the other Party pursuant to Section 1.6 or otherwise, then such monies shall, within five (5) business days after the end of the month in which they were received, be paid over by the receiving Party to the owed Party, (ii) either Party pays monies for Property Expenses that are the obligation of the other Party pursuant to Section 1.6 or otherwise, then the obligated Party shall, within five (5) Business Days after the end of the month in which the applicable invoice

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and proof of payment of such invoice are received by it, reimburse the paying Party therefor, (iii) either Party receives an invoice of an expense or obligation that is owed by the other Party pursuant to Section 1.6 or otherwise, then the receiving Party shall promptly forward such invoice to the obligated Party and (iv) if an invoice of an expense or other obligation is received by either Party and is the obligation of both Parties, then the Parties shall consult with each other and shall each promptly pay its portion of such invoice to the obligee. Each Party shall be permitted to offset any monies owed by it to the other Party pursuant to this Section 13.1C against amounts owing by it to such other Party pursuant to this Section 13.1C.

13.2    Financial Statements. Seller acknowledges that Buyer and its affiliates may be required to include statements of revenues and direct operating expenses and other financial information relating to the Transaction in documents filed by Buyer and its affiliates with the Securities Exchange Commission (the “SEC”) pursuant to the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and that such financial statements may be required to be audited. Accordingly, but subject to (y) those items that are excluded to arrive at the definition of Records, and (z) items that are Excluded Assets, from and after the date of execution of this Agreement, Seller shall use commercially reasonable efforts to (a) promptly provide Buyer with such information about the Assets that is in Seller’s possession or is provided to Seller by an Operator and that is reasonably requested by Buyer on the grounds that it is required to be included in documents filed by Buyer and its affiliates with the SEC, (b) provide, and shall cause its affiliates, officers and employees to provide, reasonable cooperation in connection with the Buyer’s preparation of documents to be filed by Buyer and its affiliates with the SEC, including providing reasonable access to employees, books and records and any existing financial data relating to the Assets that is reasonably requested by Buyer in connection with such filings with the SEC, and (c) request that Operators provide information and documents that Seller is entitled by Contract to receive and that is reasonably requested by Buyer in connection with such filings with the SEC; provided, however, that Seller shall not be required under this Section 13.2 to prepare or cause to be prepared any new reports, documents or financial data relating to the Assets.

13.3    Area of Mutual Interest. If, during the period of time from the Closing Date until two (2) year after the Closing Date, Seller, or any if its affiliates, representatives, agents, partners, successors or assigns (collectively a “Seller Party”) shall lease, purchase, trade, or otherwise acquire, either directly or indirectly any oil and gas lease, leasehold rights, mineral interest or development rights (including entering into any farmout or participation agreement) covering lands within the Transaction Area, such Seller Party shall immediately notify Buyer of such acquisition in writing, and within fourteen (14) days thereof, at Buyer’s option, exercisable in its sole discretion, such Seller Party shall assign 100% of such interest to Buyer, at such Seller Party’s actual cost, free and clear of any overriding royalties, leasehold burdens, liens or other encumbrances placed thereon by such Seller Party, pursuant to an assignment substantially in the form of Exhibit E, containing a special warranty of title by, through and under such Seller Party, but not otherwise. This Section 13.3 shall not apply to Seller’s ownership, use and development of any of the Excluded Assets.

13.4    Further Assurances. From time to time after Closing, the Parties shall each execute, acknowledge and deliver to the other such further instruments and take such other

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action as may be reasonably requested in order to accomplish more effectively the purposes of the Transaction.

ARTICLE 14.

ASSUMPTION AND RETENTION OF OBLIGATIONS AND INDEMNIFACTION

14.1    Buyer’s Assumption of Liabilities and Obligations. From and after Closing, and except for Retained Liabilities, Buyer shall assume and pay, perform, fulfill, and discharge: (a) all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to its owning, developing, exploring, or maintaining of the Assets or the producing, transporting, and marketing of Hydrocarbons from the Assets for the periods after the Effective Time, or, in the case of Taxes, to the extent apportioned pursuant to Article 9 to the period of time after the Effective Time; (b) all obligations of Seller arising under the Leases and Contracts after the Effective Time (except as otherwise provided in this Agreement); (c) the Assumed Environmental Liabilities; (d) furnishing of makeup gas and settlements of imbalances according to the terms of applicable gas sales, processing, gathering and transportation contracts; and (e) payment of royalties, overriding royalties, net profit interests or other interests or obligations attributable to the sales of Hydrocarbons after the Effective Time, (f) the payment of those amounts held in suspense for which the Purchase Price was adjusted pursuant to Section 2.4 whether attributable to the period before or after the Effective Time and (g) the Special Obligations (as later defined, but substituting Buyer in the place of any reference to Seller) to the extent attributable to the period of time after Closing (collectively, the “Assumed Liabilities”).

14.2    Seller’s Retention of Liabilities and Obligations.

A.    From and after Closing, and except for the Assumed Liabilities, Seller retains and agrees to continue to be liable to perform, fulfill and discharge all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to its owning, developing, exploring or maintaining of the Assets prior to the Effective Time, or, in the case of Taxes, to the extent apportioned pursuant to Article 9, to the period of time prior to the Effective Time.

B.    From and after Closing and except for the Assumed Liabilities, Seller retains and agrees to continue to be liable to perform, fulfill and discharge all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to (i) any injury, death, casualty, tortious action or inaction occurring on or attributable to the Assets; (ii) employee-related claims of Seller; (iii) obligations with respect to the payment or mis-payment of royalties, overriding royalties, net profits interests or other interests or obligations attributable to the sale of Hydrocarbons; and (iv) Taxes (the “Special Obligations”), in each case attributable to the period of time prior to Closing.

C.    From and after Closing, Seller retains and agrees to perform, fulfill and discharge all claims, costs, expenses, liabilities, Taxes, and obligations accruing or relating to the owning, developing, exploring or maintaining of the Excluded Assets before or after the Effective Time.

D.    To the extent the Assets are or may be deemed to be “securities” under the Securities Act of 1933, as amended, and certain applicable state securities or Blue Sky laws

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and that resales thereof may therefore be subject to the registration requirements of such acts, Seller shall retain any and all liability for Losses attributable to representations made to its investors.

The liabilities set forth in Section 14.2A, Section 14.2B, Section 14.2C and Section 14.2D are, collectively, the “Retained Liabilities.”

14.3    Indemnification. “Losses” shall mean any actual losses, costs, expenses (including court costs, reasonable fees and expenses of attorneys, technical experts and expert witnesses and the cost of investigation), liabilities, damages, demands, suits, claims, and sanctions of every kind and character (including civil fines) arising from, related to or reasonably incident to matters indemnified against.

After the Closing, the Parties shall indemnify each other as follows:

A.    Seller’s Indemnification of Buyer.    Seller assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Buyer, its officers, directors, shareholders, partners, members, affiliates, employees, agents, and successors and assigns (“Buyer Indemnified Parties”), from and against any and all Losses and causes of action, liabilities and expenses relating to, or arising out of, or connected, directly or indirectly, with the Retained Liabilities, and any breach of the Seller’s representations, warranties and covenants under this Agreement.

B.    Buyer’s Indemnification of Seller.    Buyer assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Seller, its officers, directors, employees, shareholders, partners, members, affiliates, agents, and successors and assigns (“Seller Indemnified Parties”) from and against any and all Losses and causes of action, liabilities and expenses relating to, or arising out of or connected, directly or indirectly, with the Assumed Liabilities and any breach of the Buyer’s representations, warranties and covenants under this Agreement.

C.    Release.Buyer shall be deemed to have released Seller at the Closing from any Losses for which Buyer has agreed to indemnify Seller hereunder, and Seller shall be deemed to have released Buyer at the Closing from any Losses for which Seller has agreed to indemnify Buyer hereunder. The releases in the preceding sentence shall extend to each Party’s respective officers, directors, shareholders, partners, members, representatives, employees, agents and affiliates.

14.4    Indemnification Limitations.

A.    Neither Seller nor Buyer shall not have any liability for any indemnifications under Section 14.3A or Section 14.3B for any Loss (without duplication) arising from a single event unless the amount with respect to such Loss exceeds Twenty-Five Thousand Dollars ($25,000.00) (the “Individual Indemnity Threshold”) anduntil and unless the aggregate amount of all Losses exceeding the Individual Indemnity Threshold and for which Claim Notices are delivered by the Indemnified Party prior to expiration of the applicable period under Section 14.8 exceeds Two Hundred and Fifty Thousand Dollars ($250,000.00) (the “Indemnity Deductible”), and then only to the extent such Losses exceed the Indemnity

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Deductible. Notwithstanding anything to the contrary contained in this Agreement, Seller and Buyer shall not be required to indemnify the other Party for aggregate Losses in excess of twenty percent (20%) of the Purchase Price (the “Indemnity Cap”).

B.    Notwithstanding the foregoing, (i) Seller’s obligation to indemnify Buyer for those Retained Liabilities set forth in Section 14.2B or Section 14.2C, (ii) Buyer’s obligation to indemnify Seller for those Assumed Liabilities set forth in Section 14.1(g), or, Section 14.1(c), but only with respect to any Claim asserted by delivery of a Claim Notice with respect to Section 14.1(c) on or before twenty four (24) months after the Closing Date, and (iii) either Party’s breach of the Special Representations, or any covenant or agreement contained in this Agreement, shall not be limited by Section 14.4A, and the obligation to indemnify shall be from the first dollar of any Loss, and without regard to the Individual Indemnity Threshold, the Indemnity Deductible and the Indemnity Cap.

14.5    Express Negligence. EXCEPT AS OTHERWISE PROVIDED IN SECTION 3.3, THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE AND ASSUMED OBLIGATIONS PROVISIONS PROVIDED IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LOSSES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, EXCLUDING HOWEVER THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS “CONSPICUOUS.”

14.6    Exclusive Remedy. Except for causes of action based on actual fraud or willful misconduct, notwithstanding anything to the contrary contained in this Agreement, the Parties agree that, from and after Closing, the Assignment, Section 1.7, Section 3.3, Section 4.2B, Section 4.5, Section 4.9, Section 5.4D, Section 5.5, Section 8.3C, Section 13.1A, Section 13.1B, Section 14.3A, Section 14.3B and Section 15.12 contain the Parties’ exclusive remedies against each other with respect to the Transaction, including breaches of representation, warranties, covenants and agreements of the Parties contained in this Agreement or in any document or certificate delivered pursuant to this Agreement.

14.7    Procedure. The indemnifications contained in this Article shall be implemented as follows:

A.    Claim Notice. The Party seeking indemnification under the terms of this Agreement (“Indemnified Party”) shall submit a written “Claim Notice” to the other Party (“Indemnifying Party”) which shall list the amount claimed by an Indemnified Party, the basis for such claim, with supporting documentation, and list each separate item of Loss for which payment is so claimed. The amount claimed shall be paid by the Indemnifying Party to the extent required herein within thirty (30) days after receipt of the Claim Notice, or after the amount of such payment has been finally established, whichever last occurs.

B.    Information. If the Indemnified Party receives notice of a claim or legal action that may result in a Loss for which indemnification may be sought under this Agreement

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(a “Claim”), the Indemnified Party shall give written notice of such Claim to the Indemnifying Party as soon as is practicable. If the Indemnifying Party or its counsel so requests, the Indemnified Party shall furnish the Indemnifying Party with copies of all pleadings and other information with respect to such Claim. At the election of the Indemnifying Party made within sixty (60) days after receipt of such notice, the Indemnified Party shall permit the Indemnifying Party to assume control of such Claim (to the extent only that such Claim, legal action or other matter relates to a Loss for which the Indemnifying Party is liable), including the determination of all appropriate actions, the negotiation of settlements on behalf of the Indemnified Party, and the conduct of litigation through attorneys of the Indemnifying Party’s choice; provided, however, that any settlement of the claim by the Indemnifying Party may not result in any liability or cost to the Indemnified Party without its prior written consent. If the Indemnifying Party elects to assume control, (i) any expense incurred by the Indemnified Party thereafter for investigation or defense of the matter shall be borne by the Indemnified Party, and (ii) the Indemnified Party shall give all reasonable information and assistance, other than pecuniary, that the Indemnifying Party shall deem necessary to the proper defense of such Claim. In the absence of such an election, the Indemnified Party will use its best efforts to defend, at the Indemnifying Party’s expense, any claim, legal action or other matter to which such other Party’s indemnification under this Article 14 applies until the Indemnifying Party assumes such defense. If the Indemnifying Party fails to assume such defense within the time period provided above, the Indemnified Party may settle the Claim, in its reasonable discretion at the Indemnifying Party’s expense. An Indemnifying Party (or the Indemnified Party if the Indemnified Party is defending the Claim) shall not, without the written consent of the other Party, (i) settle any Claim or consent to the entry of any judgment with respect to the Claim which does not include an unconditional written release of the Indemnified Party or the Indemnifying Party, as the case may be, from all liability in respect of such Claim, or (ii) settle any Claim or consent to the entry of any judgment with respect to the Claim in any manner that may materially or adversely affect the Indemnified Party or the Indemnified Party, as the case may be (other than as a result of money damages covered by the indemnity). If such a Claim requires immediate action, both the Indemnified Party and the Indemnifying Party will cooperate in good faith to take appropriate action so as not to jeopardize defense of such Claim or either Party’s position with respect to such Claim.

14.8    Survival.

A.    Except as provided in Section 14.8B, a Party’s representations, warranties, covenants or agreements under this Agreement will survive the Closing or terminate at the Closing (in each case, the “Survival Period”):

(a)    Except as provided in Paragraphs (b), (c), (d) and (e), all representations and warranties will survive the Closing until 5:00 o’clock p.m. prevailing Mountain Time twelve (12) months after the Closing Date;

(b)    The representations and warranties set forth in Section 5.3 will survive the Closing until 5:00 o’clock p.m. prevailing Mountain Time twelve (12) months after the Closing Date;

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(c)    The following representations and warranties will survive the Closing until the expiration of the applicable Statute of Limitations: Sections 6.1A, 6.1B, 6.2, 6.3, 6.4, 6.5, 6.6, 7.1A, 7.1B, 7.2, 7.3, 7.8, and 7.9 (the “Special Representations”);

(d)    All of the covenants, agreements, disclaimers and releases contained in this Agreement will survive the Closing in accordance with their terms.

Representations and warranties shall be of no further force and effect after the end of the respective Survival Period; provided that there shall be no termination of any bona fide Claim asserted pursuant to this Agreement by the delivery of a Claim Notice with respect to such representation or warranty prior to end of the respective Survival Period.

B.    The indemnities contained in this Agreement, including under Section 1.7, Section 3.3, Section 9.3, Section 14.3A and Section 14.3B, shall survive Closing until expiration of the applicable Statute of Limitations, and shall be of no further force and effect thereafter, except with respect to any bona fide Claim asserted pursuant to this Agreement by delivery of a Claim Notice with respect to such indemnification prior to its expiration date.

14.9    Insurance. The amount of any Losses for which any of the Buyer Indemnified Parties or the Seller Indemnified Parties, as applicable, is entitled to indemnification under this Agreement or in connection with or with respect to the Transaction shall be reduced by any corresponding insurance proceeds from insurance policies carried by the Buyer Indemnified Party or Seller Indemnified Party, as applicable, if a claim were properly pursued under the relevant insurance arrangements (net of any collection costs).

14.10    No Insurance; Subrogation. The indemnifications provided in this Agreement shall not be construed as a form of insurance. Buyer and Seller hereby waive for themselves, their respective successors or assigns, including, without limitation, any insurers, any rights to subrogation for Losses for which each of them is respectively liable or against which each respectively indemnifies the other, and, if required by applicable policies, Buyer and Seller shall obtain waiver of such subrogation from their respective insurers.

14.11    Reservation as to Non-Parties. Nothing herein is intended to limit or otherwise waive any recourse Buyer or Seller may have against any non-Party for any obligations or liabilities that may be incurred with respect to the Assets.

14.12    Noncompensatory Damages. None of the Buyer Indemnified Parties nor Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, as applicable, or their respective affiliates, any loss of profits, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising under or in connection with the Agreement or the Transaction, except to the extent any such Party is liable for such damages to a third party. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Indemnified Parties and Seller, on behalf of each of the Seller Indemnified Parties, each waive any right to recover any loss of profit, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising in connection with or with respect to this Agreement or the Transaction.

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14.13    Disclaimer of Application of Anti-Indemnity Statutes. The Parties acknowledge and agree that the provisions of Wyo. Stat. § 30-1-131 relating to oilfield services and associated activities shall not be applicable to this Agreement or the Transaction.

ARTICLE 15.

MISCELLANEOUS

15.1    Expenses. All fees, costs, and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating this Transaction shall be paid by the Party incurring the same including, without limitation, engineering, land, title, legal and accounting fees, costs and expenses.

15.2    Notices. All notices and communications required or permitted under this Agreement shall be in writing and addressed as set forth below. Any communication or delivery hereunder shall be deemed to have been made and the receiving Party charged with notice when received whether by: (i) personal delivery; (ii) mail (provided that a Party will be deemed to have received notice mailed by registered or certified mail five (5) days after mailing); or (iii) overnight courier. All notices shall be addressed as follows:

Seller

Ballard Petroleum Holdings LLC

845 12th Street

Billings, Montana 59102

Attention: David W. Ballard

Telephone: 406-259-8790

Buyer

Fidelity Exploration & Production Company

1700 Lincoln Avenue, Suite 2800

Denver, Colorado 80203

Attention: Darrell Finneman

Telephone: 303-893-3133

Fidelity Oil Co.

1700 Lincoln Avenue, Suite 2800

Denver, Colorado 80203

Attention: Darrell Finneman

Telephone: 303-893-3133

A Party may, by written notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made.

15.3    Relationship of Buyer Entities. It is not the intention of the Fidelity Exploration or Fidelity Oil to create a partnership, joint venture, mining partnership or association among

49

such entities, and neither this Agreement nor the ownership of the Assets by Fidelity Exploration and Fidelity Oil after Closing as co-tenants shall be construed as creating such a relationship. The liability of Fidelity Exploration and Fidelity Oil under this Agreement shall be several and separate, not joint or collective.

15.4    Amendments/Waiver. Except for waivers specifically provided for in this Agreement, this Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the Party claiming the benefit of such amendment or waiver.

15.5    Assignment. This Agreement may not be assigned by Buyer without prior written consent of Seller.

15.6    Announcements. Except as may be required by applicable laws or the applicable rules and regulations of any governmental agency or stock exchange, Seller and Buyer shall consult with each other with regard to all press releases and other announcements issued concerning this Agreement or this Transaction, and Buyer or Seller shall not issue any such press release or other publicity without the prior written consent of the other Party, which consent shall not be unreasonably withheld.

15.7    Counterparts/Electronic Fax Signatures. Buyer and Seller may execute this Agreement in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute but one and the same instrument. The Parties agree that facsimile signatures and signatures transmitted by electronic mail are binding.

15.8    Governing Law. This Agreement and this Transaction and any dispute resolution conducted pursuant hereto shall be construed in accordance with, and governed by, the laws of the State of Wyoming.

15.9    Entire Agreement. This Agreement constitutes the entire understanding among the Parties, their respective members, shareholders, officers, directors and employees with respect to the subject matter hereof, superseding all written or oral negotiations and discussions, and prior agreements and understandings relating to such subject matter. Each Exhibit and Schedule attached to this Agreement is incorporated into this Agreement.

15.10    Knowledge. The term “knowledge” shall mean, for purposes of this Agreement, the actual, conscious knowledge, after reasonable due inquiry, (i) in the case of Seller, David W. Ballard, Dennis Campbell or the respective manager level personnel responsible for land, legal and environmental matters, and (ii) in the case of Buyer, Darrell Finneman or Patrick Rutty.

15.11    Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties hereto and their respective successors and permitted assigns, but only those persons that will have responsibilities pursuant to this Agreement are Parties to this Agreement. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, express or implied, is intended to confer on any person or entity other than the Parties or their successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder, any rights, remedies, obligations or liabilities under or by reason of this Agreement.

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15.12    Dispute Resolution . Before commencing litigation regarding any dispute arising under this Agreement, other than any dispute covered by the dispute resolution procedures under Section 4.5, Section 5.5 or Section 13.1B, the provisions of this Section 15.11 shall apply. Each Party agrees to notify the other Party, in writing, of any such dispute.  The Parties shall then, acting in good faith, use commercially reasonable efforts to resolve the dispute as soon as possible.  If the dispute is not resolved within thirty (30) days after notice is given, then the dispute will be referred to members of senior management of each of the Parties for resolution and each Party will appoint a senior officer with the authority to settle the dispute. The senior officers so appointed will attempt to resolve the dispute within a further period of thirty (30) days from the date such referral notice is given.  If the Parties are unable to resolve the dispute within thirty (30) days of such notice, the Parties agree to endeavor to resolve the dispute through mediation.  The Parties agree to utilize good faith in selecting a mediator, scheduling the mediation and participating in the mediation.  Expenses of the mediation, excluding legal fees, shall be divided equally between the Parties.  If the dispute is not resolved through mediation, despite the Parties good faith efforts, either Party may initiate litigation within the State or Federal courts located within the State of Wyoming to resolve the dispute. Nothing in this Section 15.11 shall prevent either Party from seeking interim injunctive relief in the State or Federal courts, to maintain the status quo and avoid irreparable injury pending the outcome of the dispute resolution procedures set forth in this Section 15.11.

15.13    References, Titles and Construction.

A.    All references in this Agreement to articles, sections, subsections and other subdivisions refer to corresponding articles, sections, subsections and other subdivisions of this Agreement unless expressly provided otherwise.

B.    Titles appearing at the beginning of any of such subdivisions are for convenience only and shall not constitute part of such subdivisions and shall be disregarded in construing the language contained in such subdivisions.

C.    The words “this Agreement,” “this instrument,” “herein,” “hereof,” “hereby,” “hereunder,” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited.

D.    Words in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Pronouns in masculine, feminine, and neutral genders shall be construed to include any other gender.

E.    Unless the context otherwise requires or unless otherwise provided herein, the terms defined in this Agreement which refer to a particular agreement, instrument or document also refer to and include all renewals, extensions, modifications, amendments or restatements of such agreement, instrument or document, provided that nothing contained in this Article shall be construed to authorize such renewal, extension, modification, amendment or restatement.

F.    Examples shall not be construed to limit, expressly or by implication, the matter they illustrate.

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G.    The word “or” is not intended to be exclusive and the word “includes” and its derivatives mean “includes, but is not limited to” and corresponding derivative expressions.

H.    No consideration shall be given to the fact or presumption that one party had a greater or lesser hand in drafting this Agreement.

I.    All references herein to “$” or “dollars” shall refer to U.S. Dollars.

J.    References in this Agreement to a “business day” shall mean a day, other than a Saturday or Sunday, on which national banks are open for business in the State of Wyoming. If the date for a performance under this Agreement falls on a day that is not a business day, the date for such performance will be extended to the next business day.

K.    References in this Agreement to use “commercially reasonable efforts” or to “reasonably cooperate” or phrases of similar import shall not be interpreted to require the expenditure of any funds or the incurrence of any obligations.

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IN WITNESS WHEREOF, this Agreement has been duly executed this Agreement effective as of the Effective Time.

SELLER:
BALLARD PETROLEUM HOLDINGS LLC
By:	Ballard and Associates Inc., its sole manager
By:	/s/ David W. Ballard
	Name: David W. Ballard
	Title: President

BUYER:
FIDELITY EXPLORATION & PRODUCTION
COMPANY
By:	/s/ Patrick M. Rutty
	Name: Patrick M. Rutty
	Title: Vice President of Exploration

FIDELITY OIL CO.
By:	/s/ Darwin Subart
	Name: Darwin Subart
	Title: Chief Financial Officer

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EX-10.D

EXECUTION VERSION

Purchase and Sale Agreement

By and Between

Maurice W. Brown Oil & Gas, LLC

as Seller

and

Fidelity Exploration & Production Company

and Fidelity Oil Co.

as Buyer

Dated February 10, 2014

Dated Effective October 1, 2013

Converse County, Wyoming

3062469.3

TABLE OF CONTENTS
ARTICLE 1.	Purchase and Sale	1
1.1	Purchase and Sale	1
1.2	The Assets	1
1.3	Excluded Assets	3
1.4	Overriding Royalties and other Burdens	4
1.5	Effective Time	5
1.6	Revenue and Expenses	5
1.7	Section 1031 Exchanges	5
ARTICLE 2.	Purchase Price	5
2.1	Purchase Price	5
2.2	Deposit	5
2.3	Allocation of the Purchase Price	6
2.4	Adjustments to Purchase Price	6
2.5	Preliminary Settlement Statement	8
ARTICLE 3.	Due Diligence and Exclusive Offer	8
3.1	The Records	8
3.2	Information Disclaimer	9
3.3	Physical Access to the Assets	9
3.4	Buyer’s Other Due Diligence Activities	9
3.5	Exclusive Offer	9
ARTICLE 4.	Title Matters	10
4.1	Definitions	10
4.2	Purchase Price Adjustments for Title Defects	14
4.3	Interest Addition	15
4.4	General Disclaimer of Title Warranties and Representations	16
4.5	Disputes Regarding Title	16
4.6	Casualty Loss	17
4.7	Preferential Rights and Consents to Assign	17
4.8	Rentals, Minimum Royalties, and Shut-in Royalties	19
4.9	Excluded Contracts	19
ARTICLE 5.	Environmental Matters	19
5.1	Definitions	19
5.2	Environmental Assessment	21
5.3	Environmental Representation and Warranty	21
5.4	Environmental Liabilities and Obligations	22
5.5	Contested Environmental Defects	23
5.6	Exclusive Remedies	24

i

ARTICLE 6.	Seller’s Representations and Warranties	24
6.1	Company Representations	24
6.2	Liability for Brokers’ Fees	24
6.3	No Bankruptcy	24
6.4	Foreign Person	25
6.5	Litigation	25
6.6	Judgments	25
6.7	Compliance with Law	25
6.8	Material Contracts	25
6.9	Records	25
6.10	Property Expenses	25
6.11	Capital Projects	26
6.12	Leases	26
6.13	Licenses and Permits	26
6.14	Hydrocarbon Sales Contracts	26
6.15	Imbalance Volumes	26
6.16	Insurance	27
6.17	Plugging Obligations	27
6.18	Preferential Rights and Required Consents	27
6.19	Area of Mutual Interest, Tax Partnerships	27
6.20	Taxes	27
6.21	Title	27
6.22	Surface Access	27
6.23	Intellectual Property	27
ARTICLE 7.	Buyer’s Representations and Warranties	28
7.1	Corporate Representations	28
7.2	Liability for Brokers’ Fees	28
7.3	Litigation	28
7.4	Financing	28
7.5	Consents	28
7.6	Bankruptcy	29
7.7	Regulatory	29
7.8	Accredited Investor	29
7.9	Independent Evaluation	29
ARTICLE 8.	Covenants and Agreements	29
8.1	Covenants and Agreements of Seller	29
8.2	Covenants and Agreements of Buyer	30
8.3	Covenants and Agreements of the Parties	30
8.4	Suspense Accounts and Division of Interest	32
8.5	Record Retention	32
8.6	Disclaimers	32
ARTICLE 9.	Tax Matters	34
9.1	Definitions	34
9.2	Apportionment of Property Taxes	35

ii

9.3	Apportionment of Severance Taxes	36
9.4	Income Taxes	36
9.5	Transfer Taxes	36
9.6	Post-Closing Tax Matters	36
9.7	Allocations for Federal Income Tax Purposes	37
ARTICLE 10.	Conditions Precedent to Closing	37
10.1	Seller’s Conditions Precedent	37
10.2	Buyer’s Conditions Precedent	38
ARTICLE 11.	Termination	39
11.1	Termination	39
11.2	Remedies	39
ARTICLE 12.	Closing	40
12.1	Date of Closing	40
12.2	Place of Closing	41
12.3	Closing Obligations	41
ARTICLE 13.	Post-Closing Obligations	42
13.1	Final Settlement Statement	42
13.2	Financial Statements	43
13.3	Area of Mutual Interest	43
13.4	Further Assurances	43
ARTICLE 14.	Assumption and Retention of Obligations and Indemnification	44
14.1	Buyer’s Assumption of Liabilities and Obligations	44
14.2	Seller’s Retention of Liabilities and Obligations	44
14.3	Indemnification	45
14.4	Indemnification Limitations	45
14.5	Express Negligence	46
14.6	Exclusive Remedy	46
14.7	Procedure	46
14.8	Survival	47
14.9	Insurance	48
14.10	No Insurance; Subrogation	48
14.11	Reservation as to Non-Parties	48
14.12	Noncompensatory Damages	48
14.13	Disclaimer of Application of Anti-Indemnity Statutes	49
ARTICLE 15.	Miscellaneous	49
15.1	Expenses	49
15.2	Notices	49
15.3	Relationship of Buyer Entities	49
15.4	Amendments/Waiver	50
15.5	Assignment	50
15.6	Announcements	50

iii

15.7	Counterparts/Electronic Fax Signatures	50
15.8	Governing Law	50
15.9	Entire Agreement	50
15.10	Knowledge	50
15.11	Binding Effect	50
15.12	Dispute Resolution	51
15.13	References, Titles and Construction	51

iv

LIST OF EXHIBITS

Exhibit	Description
A	Transaction Area
B	Leases
C	Wells
D	Material Contracts
E	Form Assignment, Bill of Sale and Conveyance
F	Non Foreign Affidavit
G	Form of Seller’s Officer’s Certificate
H	Form of Buyer’s Officer’s Certificate

v

LIST OF SCHEDULES

Schedules	Description
1.3N	Excluded Properties, Interests and Rights
2.3	Allocation Schedule
4.1B.2	Contested Tax Liens
4.1B.7	Contested Mechanics Liens
4.1B.10	Contested Liens
4.7	Preferential Rights and Required Consents
5.3	Environmental Issues
6.5	Litigation
6.6	Judgments
6.10(y)	Disputed Property Expenses
6.11	Capital Projects
6.15	Imbalances
6.16	Insurance
6.17	Plugging Obligations
6.19	Area of Mutual Interest; Tax Partnership
6.20	Tax Matters
8.4	Suspense Revenues

vi

PURCHASE AND SALE AGREEMENT

Converse County, Wyoming

This Purchase and Sale Agreement (the “Agreement”), dated February 10, 2014, but effective as of October 1, 2013, is by and between Maurice W. Brown Oil & Gas, LLC, a Wyoming limited liability company, whose address is 516 South Greeley Highway, Cheyenne, Wyoming 82007 (“Seller”) and Fidelity Exploration & Production Company, a Delaware corporation (“Fidelity Exploration”), and Fidelity Oil Co., a Delaware corporation (“Fidelity Oil”), each of whose address is 1700 Lincoln Avenue, Suite 2800, Denver, Colorado 80203 (Fidelity Exploration and Fidelity Oil, collectively, “Buyer”). The transaction contemplated by this Agreement may be referred to as the “Transaction.” Seller and Buyer may be referred to individually as a “Party” or collectively as the “Parties.” The obligations of the companies comprising Buyer under this Agreement shall be several in the ratio of ninety-eight percent (98%) for Fidelity Exploration and two percent (2%) for Fidelity Oil.

Recitals

A.    Seller owns certain interests in oil and gas leases covering lands and certain oil and gas wells located in a portion of Converse County, Wyoming, as more particularly described on attached Exhibit A (the “Transaction Area”).

B.    Seller and Buyer desire that Buyer acquire one hundred percent (100%) of Seller’s interest in the Assets, as defined below, and all title and the rights associated therewith by paying the Purchase Price, as that term is defined below.

C.    To accomplish the foregoing, the Parties wish to enter into this Agreement.

Agreement

In consideration of the mutual promises herein, One Hundred Dollars ($100.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

ARTICLE 1.

PURCHASE AND SALE

1.1    Purchase and Sale. Seller agrees to sell and Buyer agrees to purchase the Assets pursuant to the terms of this Agreement.

1.2    The Assets. As used herein, the term “Assets” (or individually an “Asset”) refers to all (one hundred percent (100%)), of the Seller’s right, title and interest in and to the following:

A.The oil, gas and/or mineral leases described in Exhibit B (the “Leases”, or individually, a “Lease”) covering the lands described on Exhibit B, together with the lands pooled or unitized therewith (the “Lands”), and the oil, gas and other hydrocarbons produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination thereof, and any minerals (whether in liquid or gaseous form) produced in

1

association therewith (“Hydrocarbons”) in, on or under the Leases or Lands (including Hydrocarbons in storage or in pipelines, plants and tanks as of the Effective Time (as later defined)), including the leasehold estates and interests, contractual leasehold, other similar leasehold rights in the Leases or Lands, working interests, mineral interests, royalty interests, overriding royalty interests, production payments and net profits interests therein, together with the property and rights incident thereto, subject to those reservations, limitations or depth restrictions, if any, identified on such Exhibit B;

B.The oil and gas wells, water, injection and disposal wells on the Lands, or on lands pooled, communitized or unitized therewith as specifically described in Exhibit C (the “Wells”);

C.All personal property, inventory, equipment, fixtures or improvements used in connection with the exploration, drilling, production, gathering, treatment, processing, storing, transportation, sale or disposal of Hydrocarbons or water produced from the Wells and Leases or located on the Lands, including any gathering systems and any compressors owned by Seller (the “Equipment”);

D.The rights, interests and estates created under those certain servitudes, easements, rights-of-way, privileges, franchises, prescriptions, licenses, leases, permits and/or other rights associated with the Leases and Lands, together with any amendments, renewals, extensions, supplements, modifications or other agreements related thereto, and further together with any other servitudes, easements, rights-of-way, privileges, prescriptions, franchises, licenses, permits and/or other rights (whether presently existing or hereafter created and whether now owned or hereafter acquired by operation of law or otherwise) used, held for use in connection with, or in any way related to the properties and interests described in Sections 1.2A through 1.2J;

E.All permits, rights-of-way, surface access agreements and easements located on the Lands or used in connection with the exploration, drilling, production, gathering, treatment, processing, storing, transportation, sale or disposal of Hydrocarbons or water produced from the Leases and Lands;

F.The unitization, pooling and communitization agreements, declarations and orders, and the units created thereby and all other such agreements relating to the properties and interests described in Sections 1.2A through 1.2E and to the production of Hydrocarbons, if any, attributable to said properties and interests;

G.All contracts and contractual rights, obligations, and interests, including all farmout and farmin agreements, operating agreements, production sales and purchase contracts, gas balancing agreements, saltwater disposal agreements, surface leases, division and transfer orders, and other contracts or agreements covering or affecting any or all of the properties and interests described or referred to in Sections 1.2A through 1.2J (the “Contracts”), including the Contracts that are material to the ownership and operation of the Assets to which Seller is a party, or of which Seller has knowledge, as listed in Exhibit D (the “Material Contracts”);

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H.    All engineering, geologic, geophysical and seismic data and licenses pertaining to the properties and interests described in Sections 1.2A through 1.2J other than the Hornbuckle 3D Seismic Survey (the “Data”);

I.    All files, records and data relating to the items described in Sections 1.2A through 1.2J maintained by Seller including, without limitation, the following, if and to the extent that such files exist: all records, files, title documents, including correspondence, records of production and maintenance, revenue, sales, expenses, warranties, lease files, land files, well files, division order files, abstracts, title opinions, assignments, reports, property records, contract files, financial statements and associated work papers and work product, which relate to the items described in Sections 1.2A through 1.2J, including work product prepared by accountants, and the reserve reports and lease operating statements for the items described in Sections 1.2A through 1.2J for the years 2011, 2012, 2013, and that portion of 2014 prior to Closing and such other records as Buyer may request or are necessary for Buyer to prepare financial statements, tax returns, and other filings, but excluding from the foregoing (i) those files, records and data subject to unaffiliated third party contractual restrictions on disclosure or transfer, (ii) work product prepared by accountants in connection with Seller’s tax planning and the preparation of Seller’s income or franchise tax returns, (iii) third party reserve reports and evaluations, and (iv) audited financial statements (after such exclusions, the “Records”). To the extent that any of the Records contain interpretations of Seller, Buyer agrees to rely on such interpretations at its own risk; and

J.    All other real and personal properties, rights and titles of Seller, other than the Excluded Assets, owned by Seller and located in, or pertaining to, the Transaction Area as of the Effective Time, whether or not described in Sections 1.2A through 1.2I above, or included in an Exhibit or Schedule to this Agreement.

1.3    Excluded Assets. As used herein, the term “Excluded Assets” refers to all of Seller’s right, title and interest in and to the following, all of which are excluded from the terms of this Agreement and shall remain the sole property of Seller:

A.    All of Seller’s corporate minute books, financial records and other business records that relate to Seller’s business generally (including the ownership and operation of the Assets) and the items excluded from the Records under Section 1.2I;

B.    All trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time;

C.    To the extent they do not relate to the Assumed Obligations, all claims and causes of action of Seller arising under or with respect to any of the Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds);

D.    All rights and interests of Seller (i) under any policy or agreement of insurance or indemnity, (ii) under any bond, or (iii) to any insurance or condemnation proceeds

3

or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property prior to the Effective Time, to the extent they do not relate to the Assumed Liabilities;

E.    All Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective Time;

F.    All claims of Seller for refunds (including rights to receive refunds from any governmental entity) or loss carry forwards or credits with respect to (i) Asset Taxes (hereafter defined) allocable to Seller pursuant to Section 9.2 or Section 9.3, except to the extent such Taxes resulted in an adjustment in the final determination of the Final Purchase Price, (ii) Income Taxes of the Seller, or (iii) any Taxes attributable to the Excluded Assets;

G.    All offices, office leases of Seller, office furniture, furnishings, computer equipment, proprietary computer software, radio and telephone equipment, patents, trade secrets, copyrights, names, trademarks, logos and all other intellectual property;

H.    All documents and instruments of Seller that may be protected by an attorney/client privilege or any attorney work product doctrine, but specifically excluding title opinions;

I.    Any and all files, records, and documents relating to Seller’s sale of the Assets, including any research, valuation or pricing information prepared by Seller and/or any consultants for Seller in connection with Seller’s efforts to sell the Assets, and any offers received for such interests and information and correspondence in connection therewith;

J.    All engineering, geophysical and other seismic and related technical data and information relating to the Assets which Seller may not disclose, assign or transfer under its existing agreements and licenses without consent or without making an additional payment, or incurring any liabilities or obligations except to the extent that such payments, liabilities and obligations are permitted to be assumed by Buyer under the applicable agreements and the same are assumed by Buyer;

K.    Any debt instruments;

L.    Any of the Assets described in Section 1.2E, Section 1.2G, Section 1.2H or Section 1.2I that are not assignable, without consent or without making any additional payments, or incurring any liabilities or obligations except to the extent that such payments, liabilities and obligations are permitted to be assumed by Buyer under the applicable agreements and the same are assumed by Buyer;

M.    The Hornbuckle 3D Seismic Survey; and

N.    All other properties, interests and rights expressly reserved to the Seller and that are excluded from the Transaction under other provisions of this Agreement, including those set forth on Schedule 1.3N.

1.4    Overriding Royalties and other Burdens. As of the Effective Time, Seller has not and will not reserve or transfer an overriding royalty interest or otherwise burden the Assets,

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except that Seller has previously reserved an overriding royalty interest under the Helis Agreement (as later defined) which is to be transferred to Buyer as part of the Assets (the “Helis Overriding Royalty”).

1.5    Effective Time. The purchase and sale of the Assets shall be effective as of October 1, 2013, at 7:00 a.m. Mountain Daylight Time (the “Effective Time”).

1.6    Revenue and Expenses. Subject to the provisions hereof, Seller shall (i) remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and all other income, proceeds, receipts and credits) and (ii) remain responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Property Expenses (as later defined), in each case, attributable to the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, and subject to the occurrence of Closing, Buyer shall (iii) be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds), and (iv) be responsible (by payment, through the adjustments to the Purchase Price hereunder or otherwise) for all Property Expenses, in each case, attributable to the Assets for the period of time from and after the Effective Time.

1.7    Section 1031 Exchanges. Seller reserves the right, at or prior to Closing, to assign its rights to all or a portion of the Purchase Price, and that portion of the Assets associated therewith (“1031 Assets”), to a Qualified Intermediary (as that term is defined in Section 1.1031(k)-1(g)(4) of the Treasury Regulations) (the “QI”) to accomplish this transaction, in whole or in part, as a like-kind exchange (“Like-Kind Exchange”) under Section 1031 of the Internal Revenue Code of 1986, as amended (“Code”). Buyer hereby (i) consents to Seller’s assignment of its rights in this Agreement to the 1031 Assets, and (ii) if such an assignment is made, provided Buyer received timely notice thereof, Buyer agrees to pay all or a portion of the Purchase Price into a qualified trust account at Closing as directed in writing by Seller. Buyer likewise reserves the right, at or prior to Closing, to assign all or a portion of its rights in this Agreement to a QI or to Buyer’s Exchange Accommodation Titleholder (as that term is defined in Revenue Procedure 2000-37) (the “EAT”) in connection with effecting a Like-Kind Exchange. Seller and Buyer acknowledge and agree that a whole or partial assignment of this Agreement to a QI or EAT shall not release either Party from or expand any of their respective liabilities and obligations to each other under this Agreement. Neither Party shall be obligated to pay any additional costs or incur any additional obligations as a result of any Like-Kind Exchange effected by the other Party and each Party agrees to hold harmless and indemnify the other Party from and against all claims, losses and liabilities, if any, resulting from such Like-Kind Exchange.

ARTICLE 2.

PURCHASE PRICE

2.1    Purchase Price. The “Purchase Price” for the Assets shall be Ninety-One Million Five Hundred Thousand Dollars ($91,500,000.00).

2.2    Deposit. Contemporaneously with the execution of this Agreement, Buyer has deposited with Seller by wire transfer in same day funds, the sum of Two Million Dollars ($2,000,000.00) (the “Deposit”). The Deposit shall be distributed to Seller and credited to the

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Purchase Price at Closing, or if this Agreement is terminated, shall be distributed or retained pursuant to Article 11.

2.3    Allocation of the Purchase Price. Buyer, with Seller’s approval, has allocated the Purchase Price among the Assets as set forth on Schedule 2.3. The value so allocated to a particular Asset or spacing unit may be referred to as the “Allocated Value” for that Asset.

2.4    Adjustments to Purchase Price. All adjustments to the Purchase Price shall be made (i) according to the factors described in this Section 2.4, (ii) in accordance with generally accepted accounting principles as consistently applied in the oil and gas industry, and (iii) without duplication.

A.    Closing Amount. The term “Closing Amount” means the Purchase Price, less the Deposit, adjusted as provided in this Section 2.4, using reasonable estimates as agreed to by the Parties if actual numbers are not available.

B.    Property Expenses. For the purposes of this Agreement, the term “Property Expenses” shall mean all capital expenses (including amounts paid, leases acquired and other capital expenditures incurred after the Effective Time), and all other direct and actual expenses attributable to the Assets, including, without limitation, joint interest billings, lease operating expenses, third party overhead charges, lease rental and maintenance costs, royalties, overriding royalties, leasehold payments, Asset Taxes (as defined and apportioned as of the Effective Time pursuant to Article 9), drilling expenses, workover expenses, gathering costs, geological, geophysical and any other exploration or development expenditures chargeable under applicable operating agreements or other agreements consistent with the standards established by the Council of Petroleum Accountant Societies of North America that are attributable to the maintenance and operation of the Assets during the period in question. In no event will Property Expenses include any costs or expenses of any kind associated with Seller’s efforts to sell or market the Assets.

C.    Upward Adjustments. The Purchase Price shall be adjusted upward by the following:

1.An amount equal to all proceeds (net of royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons and Taxes not otherwise accounted for hereunder) received and retained by the Buyer from the sale of all Hydrocarbons produced from or credited to the Assets prior to the Effective Time;

2.An amount equal to all Property Expenses incurred and paid by Seller that are attributable to the period after the Effective Time;

3.To the extent not covered in the preceding paragraph, an amount equal to all prepaid expenses attributable to the Assets after the Effective Time, whether paid before, on, or after the Effective Time, that were paid by or on behalf of Seller, including applicable insurance costs, prepaid drilling and/or completion costs, and prepaid utility charges;

4.An amount equal to the Interest Addition Adjustment;

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5.    An amount equal to the value of all Hydrocarbons in storage or in the pipelines, plant and tanks as of the Effective Time that is credited or attributable to the Assets; provided that the value of oil in the production tanks shall be calculated to include only the oil stored above the load lines as of the Effective Time (i.e. Buyer is not responsible for paying Seller “tank bottoms”) and the value (i) for purposes of the Preliminary Settlement Statement, to be the actual price received for such oil, gas, or natural gas liquids, less applicable Taxes, upon the first unaffiliated third party sale thereof, if available, and upon such estimates, as are reasonably agreed upon by the Parties, to the extent actual amounts sold, or to be sold, and prices obtained, or to be obtained, are not known at Closing, and (ii) for purposes of the Final Settlement Statement, to be based upon actual amounts sold and prices obtained, less applicable Taxes, from the first unaffiliated third party sale thereof;

6.    An amount equal to the value of imbalances including, without limitation, pipeline, plant, and under-produced gas owed to Seller as of the Effective Time, with the value (i) for the purposes of the Preliminary Settlement Statement, to be the actual price received for such Hydrocarbons to be based upon actual amounts received in October of 2013, if available, and upon such estimates as are reasonably agreed upon by the Parties, to the extent actual amounts are not known at Closing, and (ii) for purposes of the Final Settlement Statement, to be based upon actual amounts sold and prices received in October 2013; and

7.    Any amounts provided elsewhere in this Agreement and any other amount agreed to by Buyer and Seller.

D.    Downward Adjustments. The Purchase Price shall be adjusted downward by the following:

1.    An amount equal to all proceeds (net of royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons and Taxes not otherwise accounted for hereunder) received and retained by the Seller from the sale of all Hydrocarbons produced from or credited to the Assets after the Effective Time;

2.    An amount equal to all Property Expenses that remain unpaid by Seller, or that have been paid by Buyer, and that are attributable to the period prior to the Effective Time;

3.    An amount equal to all cash in, or attributable to, suspense accounts held by Seller relating to the Assets for which Buyer has accepted responsibility at Closing pursuant to Section 8.4;

4.    An amount equal to (i) the value of imbalances including, without limitation, pipeline, plant, and over-produced gas owed by Seller as of the Effective Time, with the value to be based upon actual amounts received in October of 2013, if available, and upon such estimates as are reasonably agreed upon by the Parties, to the extent actual amounts are not known at Closing, and (ii) for purposes of the Final Settlement Statement, be based upon actual amounts received;

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5.    An amount equal to the Title and Environmental Defects Adjustment (hereafter defined);

6.    An amount equal to the Exclusion Adjustments (hereafter defined); and

7.    Any other amounts provided elsewhere in this Agreement, and any other amount agreed to by Buyer and Seller.

E.    Tax Adjustments. To adjust the Purchase Price for the apportionment of Taxes, the Parties agree to adjust the Purchase Price downward or upward, as appropriate, pursuant to the provisions of Article 9.

2.5    Preliminary Settlement Statement. The Purchase Price shall be adjusted at Closing pursuant to a “Preliminary Settlement Statement” prepared by Seller, submitted to Buyer, subject to Section 13.1, on or before the date that is three (3) calendar days prior to Closing. The Preliminary Settlement Statement shall set forth the Purchase Price and all adjustments thereto using the actual numbers that are available, and the resulting amount, less the Deposit, will be paid to Seller at Closing, together with the designation of Seller’s account for the wire transfer of same day funds. As soon as practicable after the receipt of the Preliminary Settlement Statement, but in no event later than the date that is one (1) calendar day prior to Closing, Buyer shall deliver to Seller a written report containing any changes that Buyer proposes to make to the Preliminary Settlement Statement. The Parties shall attempt to resolve any disputes regarding the Preliminary Settlement Statement prior to Closing. Disputes regarding the Preliminary Settlement Statement that are not resolved prior to Closing shall be resolved by the Parties on or before the Final Settlement Statement Due Date, or otherwise pursuant to Section 13.1, and the amount of such adjustments to the Purchase Price at Closing shall be that amount set forth in the written report containing Buyer’s proposed changes to the Preliminary Settlement Statement delivered by Buyer to Seller as provided in this Section 2.5, but adjusted upwards or downwards for any items that have been resolved by the Parties prior to Closing. After Closing, the Purchase Price shall be adjusted pursuant to the Final Settlement Statement delivered pursuant to Section 13.1.

ARTICLE 3.

DUE DILIGENCE AND EXCLUSIVE OFFER

3.1    The Records. From the date of this Agreement until Closing and subject to Section 8.3A, Section 8.3B and Section 8.3C, Seller will make the Records and Contracts available to Buyer for inspection, copying, and review at Seller’s offices during normal business hours to permit Buyer to perform its due diligence review. Subject to the consent and cooperation of third parties, including but not limited to the Operator (hereafter defined), Seller will use commercially reasonable efforts to assist Buyer to obtain, at Buyer’s expense, such additional information from such third parties as Buyer may reasonably desire. Buyer may inspect the Records, Contracts and such additional information only to the extent it may do so without violating any obligation of confidence or contractual commitment of Seller to a third party. Buyer acknowledges that certain third parties, not Seller, are the operators with respect to all of the Assets (each an “Operator” and together the “Operators”). As a result, pertinent

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information regarding the Assets may have to be obtained from the respective Operator, which Seller shall use commercially reasonable efforts to assist Buyer to obtain.

3.2    Information Disclaimer. Except for the representations and warranties contained in this Agreement, Seller makes no representation or warranties of any kind as to the Records, the Contracts, or any other information reviewed by Buyer. Subject to (y) the items that were excluded to arrive at the definition of Records, and (z) the items constituting the Excluded Assets, Seller represents that during the Buyer’s inspection it has not, and will not, withhold any Records, Contracts, or other information in its possession of any kind related to its ownership of the Assets, or the environmental condition or value of the Assets. Buyer agrees that any conclusions drawn from its review of the Records, Contracts and other information shall be the result of its own independent review and judgment.

3.3    Physical Access to the Assets. During reasonable business hours, Seller agrees to grant Buyer physical access to the Assets to allow Buyer to conduct, at Buyer’s sole risk and expense, on-site inspections or environmental assessments of the Assets. In connection with any on-site inspections and assessments of the Assets, Buyer agrees not to interfere with the normal operation of the Assets and agrees to comply with all operational and safety requirements of the Operators of the Assets. In connection with granting such access, Buyer represents that it is adequately insured and waives, releases and agrees to indemnify, defend and hold harmless Seller, and its directors, officers, shareholders, employees, agents, members, partners, and representatives against all claims for injury to, or death of, persons or for damage to property arising in any way from the access afforded to Buyer hereunder or the Operators or the activities of Buyer except to the extent resulting from the gross negligence or willful misconduct of Seller. This waiver, release and indemnity by Buyer shall survive termination of this Agreement. Seller will use commercially reasonable efforts pursuant to its rights under the applicable joint operating agreement to assist Buyer to obtain access rights from the respective Operator for Buyer to conduct its investigation and due diligence of the Assets under this Section 3.3; provided that Seller shall not be required to incur any liability or pay any money in order to assist Buyer to obtain such access rights. Upon completion of Buyer’s due diligence, Buyer will, at its sole costs and expense and without any cost or expense to Seller (i) repair all damage done to the Assets in connection with Buyer’s due diligence and restore the Assets to at least the approximate same condition as they were in prior to commencement of Buyer’s due diligence, and (ii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. The preceding sentence will survive the termination of this Agreement.

3.4    Buyer’s Other Due Diligence Activities. In addition to Buyer’s rights provided in Section 3.3, Seller acknowledges that Buyer will be conducting other due diligence reviews of the Assets including, without limitation, confirming (i) the quantum of the Net Revenue Acres of the Leases, and the Base NDI and Base WI of the Wells, (ii) financials, production statements and the Records, and (iii) ownership, title, acreage, and terms of the Assets.

3.5    Exclusive Offer. Upon execution of this Agreement, Seller shall not offer the Lands and Leases as described herein, entertain offers from, or negotiate for the sale of the Lands and Leases as described herein, to any third party prior to Closing or the termination of this Agreement.

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ARTICLE 4.

TITLE MATTERS

4.1    Definitions.

A.    Defensible Title. The term “Defensible Title” means such title to the Assets, that, subject to and except for Permitted Encumbrances:

1.    entitles Seller to receive the Net Decimal Interest share of the Hydrocarbons produced, saved and marketed from any Well throughout the duration of the productive life of such Well or such specified zone(s) therein of not less than the Net Decimal Interest shown in Exhibit C for such Well. As used in this Agreement, “Net Decimal Interest” (or “NDI”) with respect to a Well shall mean (i) Seller’s percentage share of the Hydrocarbons produced, saved and marketed from the Leases located within the spacing unit of such Well, after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons, multiplied by (ii) Seller’s Working Interest (as defined herein) in the Leases located within the spacing unit of such Well. The Net Decimal Interest for each Well as set forth on Exhibit C (which includes the Helis Overriding Royalty or any other overriding royalty interest in the Leases owned by Seller (unless expressly excluded pursuant to Section 1.3), where applicable) is referred to herein as the “Base NDI”). The Base NDI, which may be adjusted due to (i) decreases in connection with those operations which Seller has elected or may elect to be a non-consenting co-owner, in compliance with Section 8.1B, or (ii) decreases resulting from the establishment or amendment of pools or units, but in each case, to the extent occurring after the Effective Time and not otherwise reflected in Exhibit C is referred to herein as the “Adjusted NDI ”.

2.    obligates Seller to bear a percentage of the costs and expenses for the maintenance, development, operation and production relating to any Well throughout the productive life of such Well (“Working Interest” or “WI”) not greater than the Working Interest shown in Exhibit C for such Well (the “Base WI”) without increase, except (i) increases to the extent that they are accompanied by a proportionate increase in Seller’s Base NDI (or Adjusted NDI, if applicable), (ii) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements occurring after the Effective Time and not otherwise reflected in Exhibit C (such increases the “WI Adjustments”). The Base WI for each Well on Exhibit C, as adjusted by such Well’s WI Adjustments, will be referred to in this Agreement as the Well’s“Adjusted WI.”

3.    entitles Seller, and will entitle Buyer after Closing, to own the Net Revenue Acres in the Leases as set forth in Exhibit B. As used in this Agreement, “Net Revenue Acres” or “NRA” with respect to a Lease shall mean (i) the number of gross acres in the lands covered by the Lease, multiplied by (ii) the lessor’s percentage interest in the oil and gas fee mineral estate in the lands covered by the Lease, multiplied by (iii) Seller’s percentage leasehold interest in the Lease, multiplied by (iv) Seller’s share of the Hydrocarbons produced, saved and marketed from such Lease after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons;

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4.    entitles Seller to own its proportionate interest in all depths pertaining to the “Frontier Formation”, being the stratigraphic interval from 12,800 feet to 13,033 feet, as found in the Diamond Shamrock Co. Henry Federal 23-10 well (API No. 4900922066), located in the SW/4NE/4SW/4 of Section 10, Township 37 North, Range 74 West;

5.    is free and clear of any liens, burdens or encumbrances of any kind or character, including any surface use restriction, that would materially interfere with the operation or use of any of the Asset or materially reduce the value thereof; and

6.    is deducible from the public record (including the records of the Bureau of Land Management or the State of Wyoming - Office of State Lands) and is free from reasonable doubt to the end that a prudent person engaged in the business of ownership, development, and operation of oil and gas leases with knowledge of all the facts and their legal bearing would be willing to accept the same without adjustment to the Purchase Price.

B.    Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

1.    lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to (i) reduce the Net Revenue Acres covered by a Lease below the Net Revenue Acres for such Lease as shown on Exhibit B, (ii) reduce the NDI for such Well below the Base NDI (or Adjusted NDI, if applicable) for such Well, or (iii) increase the Base WI for such Well without a corresponding increase in the Base NDI (or Adjusted NDI, if applicable) for such Well, in each case;

2.    liens for Taxes or assessments not yet due and delinquent, or that are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are set forth on Schedule 4.1.B.2;

3.    all rights to consent by, required notices to, filings with, or other actions by federal, state or local governmental bodies, in connection with the conveyance of the applicable Asset if the same are customarily obtained after such conveyance;

4.    rights of reassignment upon the surrender or expiration of any Lease;

5.    the terms and conditions of the Contracts and all documents of record to the extent such do not (i) reduce the Net Revenue Acres covered by a Lease below the Net Revenue Acres for such Lease as shown on Exhibit B, (ii) decrease the Base NDI (or Adjusted NDI, if applicable) or increase the Base WI (or Adjusted WI, if applicable) for the affected Well, or (iii) materially interfere with the operation or use of the affected Lease or Well as has been conducted in the past;

6.    easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, on, over or in respect of any of the Assets or any restriction on access thereto that do not materially interfere with the operation or use of the affected Asset as has been conducted in the past or materially affect the value thereof;

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7.    materialmen’s, mechanics’, operators’ or other similar liens arising in the ordinary course of business incidental to operation of the Assets (i) if such liens and charges have not been filed pursuant to law and the time for filing such liens and charges has expired or (ii) if filed, such liens and charges have not yet become due and payable or are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are described on Schedule 4.1.B.7;

8.    any encumbrance on or affecting the Assets which is discharged by Seller at or prior to Closing;

9.    all rights reserved to or vested in any municipality or governmental statutory or public authority to control or regulate any of the Assets or the operations with respect thereto in any manner, and all applicable laws, rules and orders of any such authority which are not such as to materially interfere with the operation or use of any of the Assets or materially reduce the value thereof; and

10.    liens created under the Assets or operating agreements or by operation of law in respect of obligations that are not due, or that are being contested in good faith by appropriate proceedings, the proceedings of which Seller has knowledge are described on Schedule 4.1.B.10.

C.    Title Defect. The term “Title Defect” means any lien, encumbrance, claim, defect in or objection to real property title, excluding Permitted Encumbrances, that alone or in combination with other defects renders the Seller’s title to the Asset, including an individual Lease or Well, to be (i) less than Defensible Title, and (ii) the Title Defect Value of which is more than Twelve Thousand Five Hundred Dollars ($12,500.00) (with such amount being the “Individual Title Threshold”). In the event a Title Defect impacts multiple Assets, the Buyer may, in its sole discretion, aggregate the Title Defect Value of all Assets impacted by the Title Defect for the purposes of determining the Individual Title Threshold. Notwithstanding the foregoing, the following shall not be considered Title Defects:

1.    defects in the chain of title, consisting of the failure to recite marital status in a document or omissions of heirship or estate proceedings, unless Buyer provides reasonable written evidence that such failure or omission has resulted in another party claiming title to the relevant Asset;

2.    defects based upon unsubordinated Deeds of Trust or Mortgages on minerals so long as such Deeds of Trust or Mortgages were granted after the date the Lease covering such minerals was executed;

3.    defects arising out of lack of survey;

4.    defects that have been cured under applicable statutes of limitation for adverse possession or for prescription, or under Wyoming’s Marketable Title statute, Wyo. Stat. §§ 34‑10‑101, et. seq.;

5.    defects or irregularities arising out of the lack of recorded powers of attorney from corporations to execute and deliver documents on their behalf;

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6.    proof of representative capacity on behalf of a corporation, partnership, limited liability company or trust, unless it is clear from other documentation that a signatory party has not signed a document in the proper representative capacity;

7.    defects in acknowledgments;

8.    defects arising out of a lack of corporate or other entity authorization unless Buyer provides a reasonable basis for the assertion that such corporate or other entity action was not authorized and results in another person’s actual or superior claim of title to the relevant Asset;

9.    defects based upon failure to record leases issued by the Bureau of Land Management or the State of Wyoming - Office of State Lands in the real property records of the county in which the land covered by such leases is located;

10.    defects or irregularities arising out of prior oil and gas leases which have not been released of record, which on their face, expired more than, and no production attributable thereto has been reported to the Wyoming Oil and Gas Conservation Commission during the, five (5) years prior to the Effective Time (as long as Buyer does not provide evidence that such leases have been maintained by continuous production);

11.    such Title Defects as have been waived by Buyer; and

12.    defects based solely on: (i) lack of information in Seller’s files; or (ii) reference to an unrecorded document to which Seller, or a predecessor of Seller, or the Operator is not a party and which is not in the Records.

D.    Title Defect Value. “Title Defect Value” means the amount by which the Allocated Value of an Asset has been reduced by a Title Defect. In determining the Title Defect Value, the Parties intend to include only that portion of the Asset affected by the Title Defect. The Title Defect Value may not exceed the Allocated Value of the Asset and shall be determined by the Parties in good faith taking into account all relevant factors including, without limitation, the following:

1.    If the Title Defect is based upon the Seller’s owning an NDI (the “Corrected NDI”) which is less than the Base NDI (or Adjusted NDI, if applicable) for a Well, then the Title Defect Value shall be equal to the Allocated Value of the Asset multiplied by a fraction, the numerator of which is the difference between the Base NDI (or Adjusted NDI, if applicable) and the Corrected NDI and the denominator of which is the Base NDI (or Adjusted NDI, if applicable) for the Well.

2.    If the Title Defect is that the actual Net Revenue Acres covered by a Lease is less than the number of Net Revenue Acres set forth in Exhibit B for such Lease, the Title Defect Value shall be an amount equal to such difference in Net Revenue Acres multiplied by a fraction, the numerator of which is the Allocated Value of the affected Lease, and the denominator of which is the number of Net Revenue Acres set forth in Exhibit B for the affected Lease.

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3.    If the Title Defect is based on an obligation or burden that is liquidated in amount, the adjustment will be the sum necessary to remove the obligation or burden from the affected Asset; provided, however, that the adjustment shall never exceed the Allocated Value of the affected Asset.

4.    If the Title Defect is based on an obligation or burden that is not liquidated in amount (including, but not limited to, any increase in the Base WI (or Adjusted WI, if applicable) for which there is not a proportionate increase in the Base NDI (or Adjusted NDI, if applicable)), but can be estimated with reasonable certainty, the adjustment will be the sum necessary to compensate Buyer on the Closing Date for the adverse economic effect on the affected Asset; provided, however, that the adjustment shall never exceed the Allocated Value of the affected Asset.

5.    If the Title Defect (taking into account Seller’s interest in all Leases covering the same Lands) is based on a lack of rights to the Frontier Formation, the Title Defect Value shall be 66.67% of the Allocated Value of the affected Asset.

6.    If the Title Defect is a lien or encumbrance on the Asset created by Seller, Seller shall have the lien or encumbrance unconditionally released prior to Closing and if so released, there shall be no Title Defect Value associated with such lien or encumbrance.

4.2    Purchase Price Adjustments for Title Defects.

A.    Notices of Title Defects. Buyer shall give Seller a written “Title Defect Notice” on or before 5:00 p.m. Mountain Time on February 28, 2014, (the “Title Defect Date”). To be effective, each Title Defect Notice must be in writing and must satisfy the following conditions precedent: (i) name the affected Asset; (ii) describe each Title Defect in reasonable detail; (iii) describe the basis for each Title Defect; (iv) attach Supporting Documentation; (v) state the Allocated Value of the affected Asset; (vi) state Buyer’s good faith estimate of the Title Defect Value; and (vii) set forth the computations upon which Buyer’s estimate is based. For the purposes of this Section 4.2A, “Supporting Documentation” for a particular Title Defect means the following: (x) if the basis is derived from any document, a copy of such document (or pertinent part thereof); (y) if the basis is derived from any gap in Seller’s chain of title, the documents preceding and following the gap shall be attached, or in any case, other reasonable written documentation, or (z) if the basis is derived from a title opinion, then a copy of the pertinent title comment and requirement from that opinion. Buyer shall be deemed to have waived, for all purposes of this Agreement, and Seller shall have no liability for, any Title Defect existing prior to the Title Defect Date which Buyer failed to assert as a Title Defect by a properly delivered Title Defect Notice received by Seller on or before the Title Defect Date, except that for purposes of the special warranty of title in the Assignment Buyer shall be deemed to have waived only those Title Defects existing prior to the Title Defect Date (which would otherwise be subject to such special warranty) of which Buyer had knowledge, but failed to notify the Seller of on or before the Title Defect Date.

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B.    Defect Adjustments.

1.    The Purchase Price will be reduced under Section 2.4 and as set forth below, unless: (i) Seller cures, at Seller’s sole cost and expense, the Title Defect prior to Closing to Buyer’s reasonable satisfaction; (ii) Buyer agrees to waive the relevant Title Defect, which waiver may be withheld by Buyer in Buyer’s sole discretion; or (iii) Seller elects on or before Closing, to attempt to cure to Buyer’s reasonable satisfaction such Title Defect, at Seller’s sole cost and expense, no later than the Final Settlement Statement Due Date (as later defined).

2.    There shall not be any adjustment to the Purchase Price or other remedies available to Buyer (i) for any individual Title Defect for which the Title Defect Value does not exceed the Individual Title Threshold; and (ii) in no event shall there be any adjustment to the Purchase Price or other remedies available to Buyer for Title Defects that exceed the Individual Title Threshold unless (A) the sum of (1) the aggregate Title Defect Values of all such Title Defects that exceed the Individual Title Threshold (but excluding any such Title Defects (I) which are cured by Seller prior to Closing, (II) waived by the Buyer, or (III) with respect to Assets which are deemed to be Excluded Assets, other than as provided in Section 1.3) (the “1 Amount”) plus (2) the aggregate of all Environmental Defect Values that exceed the Individual Environmental Threshold (but excluding any Environmental Defects (I) which are Remediated by Seller, or (II) waived by the Buyer) (the “2 Amount”), exceeds (B) Two Million Nine Hundred Thousand ($2,900,000.00) (the “Aggregate Deductible”), after which Buyer will be entitled to an adjustment of the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the sum of the 1 Amount plus the 2 Amount exceeds the Aggregate Deductible (the “Title and Environmental Defects Adjustment”). Notwithstanding the foregoing, with respect to any Title Defect described in Section 4.1D.5, the Title and Environmental Defects Adjustment shall include the Title Defect Value of such Title Defect, first dollar, without regard to the Individual Title Threshold or Aggregate Deductible.

3.    If prior to Closing Seller elects to cure the relevant Title Defect post-Closing, the affected Asset shall not be assigned to Buyer at Closing and the Purchase Price will be reduced by the Allocated Value of such affected Asset. Seller shall have until the Final Settlement Statement Due Date to attempt to cure such Title Defect, and shall deliver evidence that any Title Defects have been cured prior to the Final Settlement Statement Due Date. Following the Final Settlement Statement Due Date, Seller shall assign to Buyer (in substantially the same form as the Assignment) the Assets affected by a Title Defect that Seller elected to cure post-Closing, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Title Defect Value of any Title Defect that has not been cured to Buyer’s reasonable satisfaction, subject to Section 4.2B.2, provided however, if the Title Defect Value equals 100% of the Allocated Value of the affected Asset, unless the Parties otherwise agree, Seller may retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

4.3    Interest Addition. Promptly on discovery, but on or before the Title Defect Date, Buyer shall in good faith notify Seller, or Seller shall in good faith notify Buyer, of any Interest Addition. As used in this Agreement an “Interest Addition” shall mean, (i) any right title or interest of Seller in any real or personal property located within or used in connection with the

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Transaction Area, other than the Excluded Assets, that are not listed on Exhibit B or Exhibit C, (ii) any interest that entitles Seller to receive (y) more than the Net Revenue Acres identified on Exhibit B for any particular Lease, (z) a higher Base NDI (or Adjusted NDI, if applicable), in any particular Well than the Base NDI (or Adjusted NDI, if applicable) for the Well, provided such increase is equal to or in excess of any proportionate increase in the Base WI (or Adjusted WI, if applicable) for such Well, or (iii) a lesser Base WI in any particular Well than the Base WI (or Adjusted WI, if applicable) for the Well, provided such decrease is in excess of any proportionate decrease in the Base NDI (or Adjusted NDI, if applicable) for such Well. Each such notice of an Interest Addition shall be in writing and shall describe the Interest Addition, the estimated Allocated Value for the Interest Addition, or the amount by which the Allocated Value of the Asset has been increased by the Interest Addition (“Value of Interest Addition”), together with the associated computations and supporting documentation. The Parties shall determine the Value of the Interest Addition in good faith in the same manner as provided in Section 4.1D, taking into account all relevant factors. The Purchase Price shall be increased for only those Value of Interest Additions that exceed the Individual Title Threshold and only to the extent the aggregate value of all Value of Interest Additions that exceed the Individual Title Threshold exceeds One Million Four Hundred Fifty Thousand Dollars ($1,450,000.00) (the “Section 4.3 Aggregate Deductible”) after which Seller will be entitled to an adjustment of the Purchase Price but only with respect to the amount by which the sum of all Value of Interest Additions exceed the Section 4.3 Aggregate Deductible (with the amount of such adjustment being the “Interest Addition Adjustment”).

4.4    General Disclaimer of Title Warranties and Representations. Except for the representations and warranties contained in this Agreement and the special warranty of title set forth in the Assignment, Seller makes no representation and warranty, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any Asset (i) in existence before the Title Defect Date, shall be as set forth in Section 4.2 or Section 4.5 or, if applicable, Section 11.1C and (ii) after the Title Defect Date, shall be pursuant to the special warranty of title set forth in the Assignment as provided in Section 4.2A.

4.5    Disputes Regarding Title. In the event of a dispute concerning (i) the scope or validity of a Title Defect, (ii) the Title Defect Value of a Title Defect, (iii) Seller’s cure of any Title Defect to the reasonable satisfaction of Buyer, (iv) the scope and validity of an Interest Addition, (v) the Value of Interest Additions, or (vi) any other matter relating to title to the Assets (a “Title Disputed Matter”), the principals of each of Buyer and Seller capable of making a final binding decision for each Party shall meet in person at the offices of Buyer, at least one (1) calendar day prior to Closing, and attempt to resolve such Title Disputed Matter. If resolution is not achieved during that meeting, then the Asset affected by such Title Disputed Matter shall not be assigned to Buyer at Closing, the Purchase Price will be reduced by the Allocated Value of such affected Asset, and such Title Disputed Matter will be determined by binding arbitration, with a single arbitrator mutually acceptable to Seller and Buyer who is licensed to practice law in the State of Wyoming and who has at least ten (10) years of mineral title examination experience (the “Title Arbitrator”). The arbitration will occur as soon as is practicable but in any event within thirty (30) days following designation of the Title Arbitrator, and the Title Arbitrator will issue a decision within ten (10) business days following completion of the arbitration. If the Parties are unable to agree upon the Title Arbitrator within ten (10) days

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of the Parties’ meeting, then either Party may apply to the court of the Eighth Judicial District in and for Converse County, Wyoming, for the appointment of the Title Arbitrator pursuant to Wyo. Stat. § 1-36-101, et seq., of the Wyoming Uniform Arbitration Act. The fees charged by the Title Arbitrator shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. Upon issuance of the Title Arbitrator’s decision, Seller shall promptly assign to Buyer (in substantially the same form as the Assignment) the Assets affected by the Title Disputed Matter, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Title Defect Value of any Title Defect that has not been cured to Buyer’s reasonable satisfaction subject to Section 4.2B.2, consistent with the Title Arbitrator’s decision, provided however, if the Title Defect Value (consistent with the Title Arbitrator’s decision) equals 100% of the Allocated Value of the affected Asset, unless the Parties otherwise agree, Seller may retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

4.6    Casualty Loss.

A.    Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and the depreciation of personal property due to ordinary wear and tear, in each case with respect to the Assets, and Buyer shall not assert any such matter as Casualty Losses (as later defined) or Title Defects under this Agreement.

B.    Prior to Closing, if a portion of the Assets is destroyed by fire or other casualty, or is taken or threatened to be taken in condemnation or under the right of eminent domain (with such event being a “Casualty Loss”), Buyer shall purchase the Asset at Closing for the Allocated Value of the Asset, reduced by an amount equal to the difference between (i) the estimated cost to repair or replace such Asset (with equipment of similar utility), less (ii) any insurance proceeds which Seller pays or causes to be paid to Buyer, up to the Allocated Value thereof (the reduction being the “Net Casualty Loss”). At its sole option, Seller may elect to cure such Casualty Loss prior to Closing, and in such event Seller shall be entitled to all insurance proceeds. If Seller elects to cure such Casualty Loss, Seller may replace any personal property that is the subject of a Casualty Loss with equipment of similar grade and utility. If Seller cures the Casualty Loss prior to Closing, Buyer shall purchase the affected Asset at Closing for the Allocated Value thereof without any Purchase Price Adjustment for such Casualty Loss.

4.7    Preferential Rights and Consents to Assign. To Seller’s knowledge, all preferential purchase rights and consents to assign affecting the Assets, except governmental consents that are customarily obtained after Closing, are set forth on Schedule 4.7. “Required Consents” include all consents and approvals except those governmental approvals which are customarily obtained post-Closing. To the extent that there are preferential purchase rights or consents to assign affecting the Assets, the provisions of this Section 4.7 shall apply. Seller shall use its commercially reasonable efforts to obtain all consents to assign. If Buyer discovers a consent to assign or preferential right to purchase during the course of Buyer’s due diligence activities that is not listed on Schedule 4.7, Buyer shall notify Seller immediately, and Seller

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shall use commercially reasonable efforts to obtain such consents or waivers and to give the notices required in connection with the preferential rights prior to Closing.

A.    Required Consents. Except with respect to the Required Consents that are conditions precedent to the Parties’ obligation to close under Article 10, as to any Asset affected by any other Required Consent that has not been obtained as of the Closing: (i) the portion of the Assets for which such Required Consent has not been obtained shall not be conveyed at the Closing; (ii) the Allocated Value for that Asset (or such portion thereof) shall not be paid to Seller; and (iii) Seller shall use commercially reasonable efforts to obtain such Required Consent as promptly as possible following Closing. If such Required Consent has been obtained as of the Final Settlement Statement Due Date, Seller shall convey the affected Asset to Buyer effective as of the Effective Time and Buyer shall pay Seller the Allocated Value of the affected Asset. If such Required Consent has not been obtained as of the Final Settlement Statement Due Date, the affected Asset shall be deemed to be an Excluded Asset. Buyer shall reasonably cooperate with Seller in obtaining any Required Consent including providing assurances of reasonable financial conditions, but Buyer shall not be required to expend funds or make any other type of financial commitments a condition of obtaining such consent.

B.    Preferential Purchase Rights. If the Parties cannot obtain a waiver of a preferential right to purchase any portion of the Assets before Closing, then the following provisions shall apply:

1.    If any preferential right to purchase is exercised and consummated prior to the Closing Date, that portion of the Assets affected by such preferential purchase right shall be an Excluded Asset and the Purchase Price shall be adjusted downward by an amount equal to the Allocated Value of such affected Assets without the requirement for Buyer to give notice.

2.    If by Closing, the time frame for the exercise of such preferential purchase rights has not expired and Seller has not received notice of an intent not to exercise or a waiver of the preferential purchase right, then Seller will retain the portion of the Assets affected by the preferential purchase right and the Purchase Price will be reduced by the Allocated Value (or a portion of the Allocated Value) for the portion of the Assets affected by the preferential purchase right. If, prior to the Final Settlement Statement Due Date, the preferential purchase right has expired without having been exercised, or has been waived, then Seller will convey the portion of the Assets affected by the preferential purchase right to Buyer pursuant to a conveyance in the form of the Assignment effective as of the Effective Time, and the Purchase Price shall be increased by the amount the Purchase Price was reduced at Closing.

C.    Exclusion Adjustments. The Allocated Values of the Assets not conveyed to Buyer at Closing by reason of the application of Section 4.2B.3, Section 4.5, Section 4.6B, Section 4.7A, Section 4.7B.1, Section 4.9, Section 5.4C, Section 5.4D, and Section 5.5 will be referred to in this Agreement as the “Exclusion Adjustments,” provided that if any such Assets are later conveyed to the Buyer as provided in this Agreement, such Assets will no longer be an Excluded Asset, and the Purchase Price for the Final Settlement Statement will be increased by the Exclusion Adjustment for such Asset.

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D.    Exclusive Remedy. Except as otherwise provided in this Agreement, the remedies set forth in this Section 4.7 are the exclusive remedies under this Agreement related to the existence and exercise of preferential purchase rights and Required Consents to assign the Assets.

4.8    Rentals, Minimum Royalties, and Shut-in Royalties. Seller shall be responsible for the payment of all rental payments, minimum royalty payments, and shut-in royalty payments, or such other payments that are necessary, due, or may become necessary or due both before and after the Effective Time, and prior to the date that is sixty (60) days after the Closing Date, other than for those portions of the Assets for which the respective Operator is responsible to make such payments to the extent attributable to the period after the Effective Time, and Buyer agrees to remit its proportionate share of all such payments due after the Effective Time to Seller within thirty (30) days of receipt of invoice for same to the extent such payment is not included as an adjustment to the Purchase Price according to Section 2.4, Section 13.1A, or Section 13.1B.

4.9    Excluded Contracts. In the event that Buyer, prior to the Title Defect Date, discovers a Contract that (i) is not listed on Exhibit D, and (ii) will materially reduce the value to Buyer, or materially impair the use or operation, of the Assets affected by such Contract, Buyer, by written notice to Seller on or before the Title Defect Date, shall have the right to exclude such Contract and the Assets affected thereby from the Transaction, and reduce the Purchase Price by the Allocated Value of such affected Assets, whereupon such Contract and the Assets affected thereby shall be Excluded Assets. After Closing, Seller shall have the right, at its sole cost and expense, to attempt to obtain a termination, amendment or waiver of, or otherwise cure, to the reasonable satisfaction of Buyer, any Contract excluded by Buyer pursuant to this Section 4.9. In the event Seller is able to terminate, amend, waive or otherwise cure any such Contract to the reasonable satisfaction of Buyer on or before the Final Settlement Date, such Contract and the Assets affected thereby shall no longer be Excluded Assets, but shall be assigned to Buyer, using the form of Assignment attached hereto as Exhibit E, and the Purchase Price for the Final Settlement Statement will be increased by the Allocated Value of such Assets.

ARTICLE 5.

Environmental Matters

The provisions of this Article apply only to the environmental matters associated with the Assets as the result of oil and gas operations on the Lands.

5.1    Definitions. For the purposes of the Agreement, the following terms shall have the following meanings:

“Environmental Consultant” means a qualified employee of the Buyer or a third party consultant reasonably acceptable to Buyer and Seller.

“Environmental Defect” means (a) a condition in, on, or under an Asset (including, without limitation, air, land, soil, surface and subsurface strata, surface water and groundwater), or any circumstance, occurrence, act or omission that (i) causes an Asset to bein material violation of an Environmental Law or (ii) requires Remediation under an Environmental Law,

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and (b) the Environmental Defect Value of which exceeds Twelve Thousand Five Hundred Dollars ($12,500.00) per incident or condition (“Individual Environmental Threshold”). It is understood and agreed that matters of an essentially similar nature such as, but not limited to, oil spills, chemical barrels, or hazardous materials found at a single site shall be deemed a single incident or condition of an Environmental Defect. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other hazardous substances. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM, asbestos and other wastes or hazardous substances. NORM containing material and other wastes or hazardous substances may have come in contact with various environmental media, including, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, NORM and other hazardous substances from the Assets. The presence of NORM, asbestos-containing materials that are non-friable, Hydrocarbons or hazardous substances cannot be claimed as an Environmental Defect, except to the extent constituting a material violation of Environmental Laws.

“Environmental Defect Notice” means each written notice given by Buyer to Seller on or before the date that is six (6) calendar days prior to Closing, as may be extended pursuant to Section 12.1 (the “Environmental Defect Date”) alleging an Environmental Defect. To be effective, each Environmental Defect Notice must be in writing and must satisfy the following conditions precedent: (i) name the affected Asset; (ii) describe the condition that causes the Environmental Defect; (iii) provide reasonable factual substantiation for the Environmental Defect; and (iv) state the estimated Remediation cost as reasonably calculated by the Environmental Consultant. Buyer shall be deemed to have waived, and Seller shall have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by Seller on or before the Environmental Defect Date.

“Environmental Defect Value” means the reasonable costs to Remediate that particular Environmental Defect.

“Environmental Law” means any and all laws, as they exist on the date hereof, (whether common or statutory), compacts, treaties, conventions, rules, regulations, orders, decrees judgments, injunctions, promulgated or entered under such laws by any federal, state, tribal or local governmental entity relating to public or employee health and safety, pollution or protection of the environment including, without limitation, common law claims and theories of liability in negligence, trespass, nuisance, strict liability or any other common law theory, Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), the Superfund Amendments and Reauthorization Act of 1986, as amended (“SARA”), the Resource Conservation and Recovery Act, as amended (“RCRA”), the Federal Safe Drinking Water Act, the Federal Water Pollution Control Act, the Emergency Planning and Community Right-to-Know Act, the Clean Air Act, the Oil Pollution Act, the Hazardous and Solid Waste Amendments Acts of 1984, as amended, and the Toxic Substances Control Act, as

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amended, including the rules of the Occupational Safety and Health Act, as amended (“OSHA”) and/or the State of Wyoming, and any and all other federal, state, tribal and local laws, rules, regulations and orders relating to reclamation of land, wetlands and waterways or relating to use, storage, emissions, discharges, cleanup, releases or threatened releases of pollutants on or into the workplace or the environment (including, without limitation, ambient air, oceans, waterways, wetlands, surface water, groundwater (tributary and non-tributary), land surface or subsurface strata), or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transportation or handling of hazardous substances, and the production, handling, processing, distribution, use, treatment, storage, disposal injection, and transportation of oil and gas and all matters utilized, handled or produced in association, including salt water.

“Remediation,” “Remediate”or “Remediated” means actions taken to correct an Environmental Defect or otherwise required to remediate an Environmental Defect in compliance with applicable Environmental Law, as recommended in writing by the Environmental Consultant.

5.2    Environmental Assessment. Buyer may conduct an onsite inspection, environmental assessment and compliance audit of the Assets (“Environmental Assessment”) at Buyer’s cost and expense. Seller shall provide Buyer with all information in Seller’s possession or control, and shall use commercially reasonable efforts assist Buyer to obtain all information from the Operator, pertaining to the environmental condition of the Asset including, but not limited to, status of any environmental audits, permits, records and assessments, and shall make available to Buyer all present personnel employed by Seller who would reasonably be expected to have knowledge or information regarding the environmental status or condition of the Assets. Buyer shall provide Seller prior written notice of any environmental inspections and tests, including sampling activities and Buyer shall give Seller the opportunity to participate in all such inspections and tests. Upon Seller’s request, Buyer shall provide to Seller, at Seller’s reasonable expense, all reports of environmental inspections and tests, provided that all such reports shall be deemed to be confidential between the Parties and subject to the confidentiality provisions of Section 8.3A. Buyer’s obligations under the first and fourth sentences of this Section 5.2 will survive termination of this Agreement. In addition, Buyer will have the environmental inspection and access rights and obligations set forth in Section 3.3.

5.3    Environmental Representation and Warranty . Except for those matters identified on Schedule 5.3, (i) to Seller’s knowledge, the Assets are being operated in material compliance with all Environmental Laws, (ii) Seller, or to Seller’s knowledge, the respective Operator, has not received a written notice of a violation of any Environmental Law from a governmental authority with respect to the Assets, (iii) to Seller’s knowledge, no notice of action alleging a material violation of an Environmental Law is pending or threatened against the Assets, (iv)  there are no civil, criminal or administrative actions, lawsuits, litigation, hearing or proceeding against the Seller, or to Seller’s knowledge the respective Operator, with respect to the Assets as a result of the violation or breach of any Environmental Law. Identifying a matter on Schedule 5.3 shall not preclude a claim by Buyer that the matter identified on Schedule 5.3 is an Environmental Defect under this Agreement. With respect to any matter identified on Schedule 5.3, Seller shall provide Buyer, within three (3) business days of execution of this Agreement, a report providing all of the information (but only to the extent of information in the

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Records and Seller’s other files) required for Buyer to prepare an Environmental Defect Notice pursuant to this Agreement for each matter identified on Schedule 5.3.

5.4    Environmental Liabilities and Obligations.

A.    Assumed Environmental Liabilities. Subject to the provisions of Section 5.4C, Section 5.4D and Section 5.5, from and after Closing, Buyer agrees to assume and pay, perform, fulfill, discharge and release Seller from all Losses relating to environmental conditions in, on, or under the Assets attributable to the period of time before and after Closing including, without limitation, any and all liability for (i) groundwater contamination; (ii) NORM; (iii) man-made material fibers; (iv) the obligation to plug and abandon all of the wells located on the Lands and reclamation of existing well sites on the Lands, other than those wells identified on Schedule 6.17; and (v) Environmental Defects (disregarding, for this purpose, the Individual Environmental Threshold and the Aggregate Deductible) attributable to the period of time before and after the Closing (collectively, the “Assumed Environmental Liabilities”).

B.    Environmental Defect Notice. For those Environmental Defects, if any, to be alleged prior to Closing, Buyer shall give Seller written notice of any Environmental Defects pursuant to an Environmental Defect Notice delivered no later than the Environmental Defect Date.

C.    Defect Adjustments. Upon delivery of a timely Environmental Defect Notice, the Parties shall proceed as set forth in this Section 5.4. With respect to those Environmental Defects that are not contested by Seller, Seller shall elect one of the following options: (i) to Remediate, at Seller’s sole cost and expense, the Environmental Defect on the affected Assets as promptly as practicable prior to Closing, such Remediation to be consistent with Environmental Laws and to the reasonable satisfaction of Buyer; (ii) to attempt to Remediate, at Seller’s sole cost and expense, the specified Environmental Defect(s) consistent with Environmental Laws after Closing and to the reasonable satisfaction of Buyer, as provided in Section 5.4D; (iii) with Buyer’s consent, which may be withheld in its sole discretion, to reduce the Purchase Price by the Environmental Defect Value, in which event Buyer hereby releases Seller from any further obligations relating to the Environmental Defects for which the Purchase Price was reduced; or (iv) to retain the Asset affected by such Environmental Defect and reduce the Purchase Price by the Allocated Value of such affected Asset, in which case the affected Asset shall become an Excluded Asset. Notwithstanding anything in this Section 5.4C, there shall not be any adjustment to the Purchase Price or other remedies available to Buyer (i) for any Individual Environmental Defect for which the Environmental Defect Value does not exceed the Individual Environmental Threshold; and (ii) in no event shall there be any adjustment to the Purchase Price for Environmental Defects that exceed the Individual Environmental Threshold, except to the extent the Aggregate Deductible is exceeded, as provided in Section 4.2B.2.

D.    Post-Closing Remediation. If Seller elects to Remediate an Environmental Defect(s) post-Closing, the Asset affected by the Environmental Defect will be deemed to be an Excluded Asset and will be retained by Seller at Closing, and the Purchase Price will be reduced by the Allocated Value of the Asset affected by the Environmental Defect(s). If Seller Remediates the Environmental Defect(s) to Buyer’s reasonable satisfaction on or before the Final

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Settlement Due Date, Seller will convey the affected Asset to Buyer effective as of the Effective Time, and the Final Settlement Statement will be adjusted upwards by an amount equal to the reduction in the Purchase Price at Closing with respect to such Asset. If Seller does not Remediate the Environmental Defect(s) to Buyer’s reasonable satisfaction by the Final Settlement Statement Due Date, then unless (a) Seller and Buyer agree that the affected Assets will be conveyed to Buyer for an amount equal to the Allocated Value thereof less the Environmental Defect Value, subject to Section 4.2B.2, or such other amount as is agreed by the Parties, (b) Seller will retain the affected Asset and there will be no further downward adjustment to the Purchase Price, and such affected Asset shall become an Excluded Asset. If the Parties agree on alternative (a), Seller will convey the Asset affected by the Environmental Defect to Buyer effective as of the Effective Time, and the Final Settlement Statement will be adjusted by the amount agreed upon by the Parties with respect thereto. During the period of time from Closing to the Final Settlement Statement Due Date, Buyer agrees to afford Seller and its officers, employees, and other authorized representatives reasonable access, during normal business hours, to the Assets and all Records in Buyer’s or any of its affiliates’ possession in order to facilitate Seller’s attempt to cure such Environmental Defect(s).

5.5    Contested Environmental Defects. If Seller contests the existence of an Environmental Defect or the Environmental Defect Value, Seller shall notify Buyer in writing on or before four (4) calendar days after receipt of the Environmental Defect Notice (“Rejection Notice”). The Rejection Notice shall state with reasonable specificity the basis of the rejection of the Environmental Defect or the Environmental Defect Value. If Seller fails to timely deliver a Rejection Notice, Seller shall be deemed to have accepted the validity of the Environmental Defect and Buyer’s estimate of the Environmental Defect Value, and shall be deemed to have waived its own option to contest the Environmental Defect pursuant to Section 5.4 or this Section 5.5. Within one (1) calendar day of receipt of the Rejection Notice, representatives of Buyer and Seller knowledgeable in environmental matters shall meet and, either (i) mutually agree to reject the particular Environmental Defect; (ii) agree on the validity of such Environmental Defect and the Environmental Defect Value; or (iii) agree that the Asset affected by such Environmental Defect shall be retained by Seller and shall become an Excluded Asset. If the Parties cannot agree on any option in the preceding sentence, then disputed matters relating to the validity of a claimed Environmental Defect or Environmental Defect Value, whether an Environmental Defect has been Remediated to Buyer’s reasonable satisfaction or any other disputed environmental matters (“Environmental Disputed Matters”) will be determined by binding arbitration, with a single arbitrator mutually acceptable to Seller and Buyer who either is a reputable environmental consultant or is licensed to practice law in the State of Wyoming and who has at least ten (10) years of environmental consulting or environmental law experience (the “Environmental Arbitrator”). The arbitration will occur as soon as practicable but in any event within thirty (30) days following designation of the Environmental Arbitrator, and the Environmental Arbitrator shall issue a decision within ten (10) business days following completion of the arbitration. The Environmental Arbitrator’s determination shall be final and binding upon Seller and Buyer and enforceable in any court of competent jurisdiction. The fees charged by the Environmental Arbitrator shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. In the event that arbitration of any Environmental Disputed Matters is required and the arbitration is not completed by Closing, the affected Asset shall not be assigned to Buyer at Closing and the Purchase Price will be reduced by the Allocated Value of such affected Asset. Upon issuance of the Environmental Arbitrator’s decision, Seller, at Seller’s

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option, may either (i) with Buyer’s consent, which may be withheld in its sole discretion, assign to Buyer (in substantially the same form as the Assignment) the Asset affected by the Environmental Disputed Matter, and there shall be an upward adjustment in the Final Settlement Statement for the Allocated Value of the affected Asset, less the Environmental Defect Value of any Environmental Defect that has not been Remediated to Buyer’s reasonable satisfaction, subject to Section 4.2B.2 consistent with the Environmental Arbitrator’s decision, or (ii) retain the affected Asset, in which event the affected Asset will be an Excluded Asset.

5.6    Exclusive Remedies. Except as otherwise provided in this Agreement, the rights and remedies granted each Party in this Article, including the rights of each Party to not close pursuant to Article 11.1C, are the exclusive rights and remedies against the other Party related to any Environmental Defect or other environmental matters.

ARTICLE 6.

SELLER'S REPRESENTATIONS AND WARRANTIES

Seller makes the following representations and warranties as of the execution of this Agreement and as of Closing:

6.1    Company Representations.

A.    Status and Authority. Seller is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Wyoming. Seller has all requisite power and authority to own the Assets, to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other document executed or to be executed by Seller in connection with the Transactions contemplated herein. The execution, delivery, and performance by Seller of this Agreement and each other document executed or to be executed by Seller in connection with the Transaction and the consummation by it of the Transaction have been duly authorized by all necessary limited liability company actions of Seller.

B.    No Violation. Assuming the receipt of all Required Consents, the execution and delivery of this Agreement and the consummation of the transactions contemplated hereby do not and will not: (i) create a lien or encumbrance on the Assets that will remain in existence after Closing; (ii) violate, or be in conflict with, any provision of Seller’s governing documents, (iii) violate or conflict with any provision of any statute, rule or regulation applicable to Seller or the Assets or any Material Contract, or (iv) violate, or be in conflict with, any judgment, decree or order applicable to Seller, except in the case of clauses (iii) and (iv) where such violation or conflict would not have a material effect upon the ability of Seller to consummate the Transaction and perform its obligations under this Agreement.

6.2    Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to this Transaction for which Buyer shall have any responsibility whatsoever.

6.3    No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, to the knowledge of Seller, threatened against Seller by any third party.

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6.4    Foreign Person. Seller is not a “foreign person” within the meaning of the Internal Revenue Code of 1986, as amended (the “Code”), Sections 1445 and 7701 (i.e., Seller is not a nonresident alien, foreign corporation, foreign partnership, foreign trust, or foreign estate as those terms are defined in the Code and any regulation promulgated thereunder).

6.5    Litigation. Except as set forth on Schedule 6.5, there are no suits, actions, arbitrations or other proceedings by or before any court, arbitrator or other governmental agency pending against Seller (or to Seller’s knowledge, the respective Operator) or, to Seller’s knowledge, threatened in writing against Seller or the respective Operator, which relate to (and could diminish the value of or impede the operation of) the Assets or the Transaction.

6.6    Judgments. Except as set forth on Schedule 6.6, there are no unsatisfied judgments or injunctions issued by a court of competent jurisdiction or other governmental agency outstanding against Seller (or to Seller’s knowledge, the respective Operator) that would be reasonably expected to materially interfere with the operation of any of the Assets, or materially affect the value of any of the Assets, or impair Seller’s ability to enter into this Agreement or consummate this Transaction.

6.7    Compliance with Law. To Seller’s knowledge, the Assets have been operated in material compliance with all applicable federal, state and local laws, rules, regulations and orders, excluding Environmental Laws, the Seller’s representations and warranties with respect to which are in Section 5.3, Seller (or to Seller’s knowledge, the respective Operator) has not received a notice of a violation of any statute, law, ordinance, regulation, permit, rule or order of any federal, state, tribal or local government or any other governmental department or agency, or any judgment, decree or order of any court, applicable to the Assets or operations of the Assets, which remains uncured.

6.8    Material Contracts. Exhibit D includes all of the contracts and agreements that are material to the ownership and operation of the Assets to which Seller is a party, or of which Seller has knowledge. To Seller’s knowledge, the Material Contracts are in full force and effect and constitute valid and binding obligations of the parties thereto. Seller is not in breach, violation or default (and no situation exists which with the passing of time or giving of notice would create a breach, violation, or default) of its obligations under the Material Contracts, and to Seller’s knowledge there is no breach, violation, or default under the Material Contracts by any third party (and no situation exists which with the passing of time of giving of notice would create a breach, violation, or default) exists.

6.9    Records. Subject to (y) the items excluded to arrive at the definition of Records, and (z) items which are Excluded Assets, Seller represents that: (i) all of the Records are files, or copies thereof, that Seller has used in the ordinary course of operating and owning the Assets; (ii) Seller has not intentionally withheld any material information from the Records; and (iii) Seller has not intentionally misrepresented any material information in the Records.

6.10    Property Expenses. In the ordinary course of business, (i) Seller has paid its share of all Property Expenses attributable to the period of time prior to the Effective Time as such Property Expenses become due, and (ii) such Property Expenses are being paid in a timely manner before the same become delinquent, except (y) such Property Expenses as are disputed in

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good faith by Seller in a timely manner and for which Seller shall retain responsibility, as set forth on Schedule 6.10(y), and (z) except such Property Expenses as have or will be taken into account as an adjustment to the Purchase Price under Section 2.4.

6.11    Capital Projects. Schedule 6.11 is a list and description of all wells or other specified capital projects, of which Seller has been made aware, to the extent such capital projects will extend beyond the Effective Time, and associated costs or estimates thereof to the extent such costs or estimates are reasonably estimated to exceed Fifty Thousand Dollars ($50,000.00) per well or project net to Seller’s interest (the “Capital Projects”). All costs and expenses incurred by the Parties with respect to the Capital Projects will be apportioned between the Parties as of the Effective Time, with Buyer assuming all post-Effective Time costs and expenses and Seller retaining all pre-Effective Time costs and expenses.

6.12    Leases. To Seller’s knowledge, all conditions necessary to keep each Lease in full force and effect in accordance with its terms have been performed and all material obligations under the Leases have been fully performed, including the proper and timely payment of all royalties, rentals, shut-in payments and other payments due under the Leases. To Seller’s knowledge, there are no currently pending requests or demands for payments, adjustments of payments or performance pursuant to obligations under the Leases. Seller (or to Seller’s knowledge, the respective Operator) has not received a written notice of default with respect to the payment or calculation of rentals and royalties attributable to the Assets.

6.13    Licenses and Permits. Seller (or to Seller’s knowledge, the respective Operator) has all governmental licenses, permits, authorizations, consents, and approvals required for the ownership of the Assets, and has materially complied with all applicable rules, regulations, and ordinances of any governmental authority having jurisdiction over the Assets and as to which non-compliance would have a material effect on the Assets or any of them.

6.14    Hydrocarbon Sales Contracts. Except under the Contracts, Seller (or to Seller’s knowledge, the respective Operator) has not (i) sold forward any Hydrocarbons or (ii) received any material advance, “take-or-pay” or other similar payments under production sales contracts that entitle the purchasers to “make up” or otherwise receive deliveries of Hydrocarbons without paying at such time the contract price therefor. To Seller’s knowledge, and except under the Contracts, no Hydrocarbons are subject to a sales contract (other than division orders or spot sales agreements terminable on no more than thirty (30) days’ notice) and no person has any call upon, option to purchase or similar rights with respect to the production from the Assets and the Assets are not bound by futures, hedge, swap, collar, put, call, floor, cap, option or other contracts that are intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, securities, foreign exchange rates or interest rates. Proceeds from the sale of oil, condensate, and gas from the Assets are being received in all respects by Seller in a timely manner and are not being held in suspense for any reason.

6.15    Imbalance Volumes. To Seller’s knowledge, except as identified on Schedule 6.15, as of the Effective Time and as of Closing, there will not exist any material imbalances (a) with any gatherers, processors, or transporters associated with the Assets where Seller has received a quantity of gas prior to the Effective Time for which Seller will have a duty

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after the Effective Time to deliver an equivalent quantity of gas or pay a sum of money, and (b) relating either to production from or at the wellhead between to co-tenant or working interest owners in a well, unit, or field which are associated with the Assets where Seller has received any quantity of gas prior to the Effective Time for which Buyer will have a duty after the Effective Time to deliver an equivalent quantity of gas or pay a sum of money.

6.16    Insurance. Seller maintains, and through the Closing Date will maintain, with respect to the Assets, the insurance coverage described on Schedule 6.16.

6.17    Plugging Obligations. To Seller’s knowledge, only the Wells listed on Schedule 6.17 are currently obligated by law or contract to be plugged and abandoned in compliance with all applicable requirements of regulatory authority having jurisdiction thereof.

6.18    Preferential Rights and Required Consents . Except as identified on Schedule 4.7 and for consents of federal and state agencies or authorities in connection with the assignment of any federal and state leases or interest therein, there are no preferential rights of purchase or consents to assign in favor of third parties with respect to the Assets.

6.19    Area of Mutual Interest, Tax Partnerships. Except as identified on Exhibit D or Schedule 6.19, no Asset is subject to (or has related to it) any area of mutual interest agreements or any farm-out or farm-in agreement under which any party thereto is entitled to receive assignments not yet made, or could earn additional interests in or assignments of all or any portion of the Assets after the Effective Time, or contain any drilling commitments that Buyer would be obligated to satisfy after the Effective Time. No Asset is owned by, subject to, or has related to it in any way, directly or indirectly, any tax partnership for federal, state or local tax purposes.

6.20    Taxes. All due and payable Taxes (as later defined) with respect to the Assets, which became due prior to the Closing Date for any periods prior to the Effective Time, have been properly paid, or if not due prior to the Closing Date for any periods prior to the Effective Time, adequate provision has been made for their payment. With respect to the Assets, there are no suits, actions, claims, investigations, audits, inquiries or proceedings pending, or to Seller’s knowledge threatened, against Seller in respect of Taxes. There are no tax liens burdening the Assets, except liens for current Taxes not yet due and payable and for which adequate provision has been made for their payment. Notwithstanding the foregoing, Seller’s representation and warranties under this Section 6.20 are limited to Seller’s knowledge with respect to any Taxes payable by the Operator.

6.21    Title. Seller warrants title to the Assets only as provided in the Assignment.

6.22    Surface Access. To Seller’s knowledge, there are no surface use or access agreements currently in force and effect that would materially interfere with oil and gas operations on the Leases.

6.23    Intellectual Property. There are no trademarks, trade names, patents, service marks, brand names, computer programs, databases, industrial designs, copyrights or other intangible property owned or licensed by Seller (the “Intellectual Property”), that are materially necessary for the operation, or continued operation of any Asset, or for the ownership and

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operation, or continued ownership and operation, of any Asset, except for the Intellectual Property which is a part of the Assets.

ARTICLE 7.

Buyer’s Representations and Warranties

Buyer makes the following representations and warranties to Seller as of the execution of this Agreement and as of Closing:

7.1    Corporate Representations. Each Buyer makes the following representations and warranties with respect to itself:

A.    Status and Authority. Buyer is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is authorized to conduct business in Wyoming. Buyer has all requisite power and authority to own the Assets, to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other document executed or to be executed by Buyer in connection with the Transactions contemplated herein. The execution, delivery, and performance by Buyer of this Agreement and each other document executed or to be executed by Buyer in connection with the Transaction and the consummation by it of the Transaction have been duly authorized by all necessary company and/or corporate actions of Buyer.

B.    No Violation. The execution and delivery of this Agreement does not (i) violate or conflict with any provision of Buyer’s governing documents, or any provision of any statute, rule or regulation applicable to Buyer or any material lease, contract, agreement, instrument or obligation to which Buyer is a party or by which Buyer is bound or (ii) violate or conflict with any judgment, decree or order applicable to Buyer.

7.2    Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to this Transaction for which Seller shall have any responsibility whatsoever.

7.3    Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or governmental body pending or, to Buyer’s knowledge, threatened in writing against it before any governmental authority that impedes or is likely to impede Buyer’s ability to consummate this Transaction and to assume the liabilities to be assumed by Buyer under this Agreement, including without limitation, the Assumed Liabilities.

7.4    Financing. As of Closing, Buyer has the financial resources available to close this Transaction without financing that is subject to any contingency and to fund the obligations required by this Agreement.

7.5    Consents. There are no consents, including requirements for consents from third parties, in each case, that Buyer is required to obtain in connection with its acquisition and ownership of the Assets as contemplated by this Agreement.

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7.6    Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened in writing against Buyer or any affiliate of Buyer.

7.7    Regulatory. Buyer is and hereafter shall continue to be qualified to own and assume operatorship of the Assets in the jurisdiction where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator.

7.8    Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any state blue sky laws or any other securities Laws.

7.9    Independent Evaluation. Buyer is experienced and knowledgeable in the oil and gas business and is aware of its risks. Buyer has been afforded the opportunity to examine the Records, and materials made available to it by Seller with respect to the Assets (the “Background Materials”). The Background Materials include files, or copies thereof, that Seller has used in its normal course of business and other information about the Assets that Seller has compiled or generated.

ARTICLE 8.

COVENANTS AND AGREEMENTS

8.1    Covenants and Agreements of Seller. Seller covenants and agrees with Buyer as follows:

A.    Operations and Status Prior to Closing. From the date of execution hereof to the Closing, Seller will maintain (and shall use commercially reasonable efforts to cause the Operator to maintain) the Assets in a manner consistent with its past practices. Seller agrees to maintain the insurance that it now has in effect with respect to the Assets through the date of Closing. From the date of execution of this Agreement to the Closing Date, Seller shall pay or cause to be paid its share of all Property Expenses incurred in connection with the ownership or operation of the Assets, subject to adjustment to the Purchase Price pursuant to Section 2.4 and shall maintain the insurance described in Schedule 6.16. Seller shall maintain its limited liability company status from the date hereof until Closing to assure that as of the Closing Date, Seller will not be under any material, legal or contractual restriction that would prohibit or delay the timely consummation of this Transaction.

B.    Restriction on Operations. Except (x) for operations covered by Capital Projects, (y) for actions taken in connection with emergency situations or to maintain a Lease that is otherwise about to expire, and (z) as expressly contemplated by this Agreement, unless Seller obtains the prior written consent of Buyer to act otherwise, from the date of execution of this Agreement to the Closing Seller shall not (i) propose or approve any operations on the Assets anticipated to cost, net to the Seller’s interest, more than Fifty Thousand Dollars ($50,000.00) per activity, (ii) convey or dispose of any part of the Assets (other than replacement

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of equipment or sale of Hydrocarbons or obsolete equipment in the regular course of business); (iii) enter into any new farmout, farmin or other similar contract affecting the Assets, (iv) enter into any new contracts affecting the Assets with obligations in excess of thirty (30) days other than such new contracts which are terminable on not more than thirty (30) days’ notice; (v) abandon any Well or release (or permit to terminate), or modify its rights under all or any portion of the Leases; (vi) modify or terminate any Material Contract; and (vii) respond to any, or fail to respond, to any notices of forced pooling or spacing applications pertaining to Leases or Lands without providing a copy of said notice to Buyer and allowing Buyer to determine how to respond to said notice on behalf of Seller. Buyer acknowledges that Seller owns undivided interests in the Assets that the Seller is not the operator thereof, and Buyer agrees that the acts or omissions of the other working interest owners (including the Operators) shall not constitute a breach of the provisions of this Section 8.1B, and no action required of other working interest owners shall constitute a breach of this Section 8.1B, so long as Seller has voted its interest in a manner that complies with the provisions of this Section 8.1B.

C.    Operatorship. In the event any Operator resigns or is deemed to have resigned as operator of any of the Assets pursuant to the terms of the applicable joint operating agreement pertaining to such Assets, Seller shall vote solely for Ballard Petroleum Holdings LLC, pursuant to the terms of the applicable joint operating agreement, to succeed as operator of such Assets. This obligation shall survive Closing with respect to any Assets not conveyed to Buyer at Closing by reason of the application of Section 4.2B.3, Section 4.5, Section 4.6B, Section 4.7A, Section 4.7B.1, Section 5.4C, Section 5.4D or Section 5.5, until such Assets are conveyed to Buyer or conclusively determined to be Excluded Assets.

D.    Notification of Claims. Seller shall promptly notify Buyer of any suit, action or other proceeding before any court or governmental agency and any cause of action that relates to the Assets or that might result in impairment or loss of Seller’s title to any portion of the Assets or the value thereof or that might hinder or impede the operation of the Leases arising or threatened prior to the Closing.

8.2    Covenants and Agreements of Buyer. Buyer covenants and agrees with Seller that Buyer shall maintain its limited liability company status from the date hereof until the Closing Date and use all reasonable efforts to assure that as of the Closing Date it will not be under any material, legal or contractual restriction that would prohibit or delay the timely consummation of this Transaction.

8.3    Covenants and Agreements of the Parties. The Parties covenant and agree as follows:

A.    Confidentiality. Subject to Section 15.6, all data and information, whether written or oral, obtained from either Party in connection with this Transaction, including the Records, whether obtained by either Party before or after the execution of this Agreement, data and information generated by either Party in connection with this Transaction, and all information regarding the existence of this Transaction (collectively, the “Information”), is deemed by the Parties to be confidential and proprietary of the Parties. Until the Closing and for a one (1) year period after the Closing, except as required by law or applicable stock exchange rule, the Parties and its officers, agents and representatives will hold in strict confidence the

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terms of this Agreement, and all Information, except any Information which: (i) at the time of disclosure to one Party by the other Party is in the public domain; (ii) after disclosure to one Party by the other Party becomes part of the public domain by publication or otherwise, except by breach of this commitment by either Party; (iii) the Parties can establish by competent proof was rightfully in the other Party’s possession at the time of disclosure; (iv) either Party rightfully receives from third parties free of any obligation of confidence; (v) is developed independently by either Party without the Information, provided that the person or persons developing the data shall not have had access to the Information, (vi) is disclosed to a Party’s attorneys, accountants, lending institutions, members and shareholders, subject to the same confidentiality restrictions as are set forth in this Section 8.3A, or (vii) the relevant details regarding the Transaction are disclosed to third parties in order to obtain Required Consents, or the relevant parts of this Agreement are disclosed to third parties to deal with preferential rights to purchase under Section 4.7B. In the event the Closing does not occur, the Parties will be bound by the terms and conditions of that certain Confidentiality Agreement dated August 7, 2013.

B.    Return of Confidential Information. If this Transaction does not close on or before Closing, or such later date as agreed to by the Parties, Buyer shall (i) return to Seller all copies of the Confidential Information in possession of Buyer obtained pursuant to any provision of this Agreement; (ii) destroy any and all notes, reports, studies or analyses based on or incorporating the Confidential Information. The terms of Section 8.3A, Section 8.3B, and Section 8.3C shall survive termination of this Agreement.

C.    Injunctive Relief. Buyer and Seller agree that they will not have an adequate remedy at law if the other Party violates any of the terms of Sections 8.3A and/or Section 8.3B. In such event, the non-breaching Party will have the right, in addition to any other it may have, to obtain injunctive relief to restrain any breach or threatened breach of the terms of Sections 8.3A and/or Section 8.3B, or to obtain specific enforcement of such terms.

D.    Notice of and Cure Period for Breach. If, prior to Closing, either Seller or Buyer develops or possesses information that leads it to believe that the other Party may have breached a representation, warranty or covenant under this Agreement that Party shall promptly notify the other Party of such potential breach. Any breach of this Agreement may be cured within 48 hours after the notification, exclusive of weekends and holidays, of receipt of written notice of such breach. Notwithstanding the foregoing, this Article shall not apply to breach of the Parties’ obligations at and after Closing and shall not operate to delay Closing.

E.    Notice of Material Adverse Effect. If, prior to Closing, either Seller or Buyer develops, receives or possesses information of a potential Material Adverse Effect not known by or previously disclosed to the other Party, such Party shall promptly notify the other Party of such potential Material Adverse Effect. As used in this Agreement, “Material Adverse Effect” shall mean any state of facts, change, event, effect or occurrence (when taken together with all other states of fact, changes, events, effects or occurrences), that is (i) materially adverse to the ownership, use, operations or value of the Assets, as a whole, or (ii) materially adverse to the ability of the Parties to consummate the transactions contemplated by this Agreement in a timely manner. Notwithstanding the foregoing, the following shall not be considered a Material Adverse Effect: (a) national or international business, economic or political conditions; (b) events affecting the financial, banking or securities markets; (c) conditions (or changes in

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such conditions) generally affecting the oil and gas industry; (d) increases in energy, electricity, natural gas, oil, or other raw materials or operating costs; (e) changes in generally accepted accounting principles or Law; (f) any event of force majeure; (g) changes in oil or natural gas prices, including changes in price differentials; or (h) acts of terrorism, sabotage, or war, whether declared or undeclared.

8.4    Suspense Accounts and Division of Interest. Seller has identified, listed, and scheduled the amount of all revenues or royalties currently held in suspense by Seller related to the Assets along with a brief description of the justification for the suspension in Schedule 8.4. At the Closing, Seller will provide to Buyer: (i) information regarding all of Seller’s accounts holding moneys in suspense together with a written explanation (as contained in Seller’s files) of why such moneys are held in suspense or other information identifying the proper disposition of such moneys and (ii) Seller’s division of interest and all supporting documentation regarding those royalty owners and working interest owners in the Leases for whom Seller disburses proceeds of production, together with all accounts holding funds payable to such third parties. From after Closing, Buyer agrees to pay and perform all of Seller’s obligations with respect to the suspense accounts listed on Schedule 8.4.

8.5    Record Retention. Seller may retain copies of all of the Records. For so long as Buyer owns an interest in the Assets, Buyer shall (a) retain the Records, (b) provide each Seller, its affiliates and its respective officers, employees and representatives with access to the Records during normal business hours for review and copying at Seller’s expense and (c) provide Seller, its affiliates and its respective officers, employees and representatives with access, during normal business hours, to materials received or produced after Closing relating to any indemnity claim made under Article 14 for review and copying at Seller’s expense.

8.6    Disclaimers.

A.    EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT OR THE ASSIGNMENT, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF THEIR AFFILIATES).

B.    EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN THIS AGREEMENT OR THE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR

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SEISMIC DATA OR INTERPRETATION RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES TO BE GENERATED BY THE ASSETS, (V) THE PRODUCTION OF OR ABILITY TO PRODUCE HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR RESPECTIVE EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN THIS AGREEMENT, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, OR ANY CLAIM BY BUYER FOR DAMAGES OR DEFECTS, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

C.    EXCEPT AS TO THE LIMITED EXTENT REPRESENTED OTHERWISE IN SECTION 5.3, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

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D.    SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 8.6 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY LAW.

ARTICLE 9.

TAX MATTERS

9.1    Definitions. For the purposes of this Agreement:

A.    “Asset Taxes” means all Property Taxes and Severance Taxes.

B.    “Income Taxes” means all Taxes based upon, measured by, or calculated with respect to (a) gross or net income or gross or net receipts or profits (including, but not limited to, franchise Tax and any capital gains, alternative minimum Taxes, net worth and any Taxes on items of Tax preference, but not including sales, use, goods and services, real or personal property transfer or other similar Taxes), (b) multiple bases (including, but not limited to, corporate franchise, doing business or occupation Taxes) if one or more of the bases upon which such Tax may be based upon, measured by, or calculated with respect to, is described in clause (a) above, or (c) withholding Taxes measured with reference to or as a substitute for any Tax described in clauses (a) or (b) above, and (d) and any penalties, additions to Tax, and interest levied or assessed with respect to a Tax described in (a), (b), or (c).

C.     “Property Taxes” means all ad valorem, real property, personal property, and all other Taxes and similar obligations, and any penalties, additions to Tax, and interest levied or assessed thereon, assessed against the Assets or based upon or measured by the ownership of the Assets, but not including Income Taxes, Severance Taxes, or Transfer Taxes.

D.    “Severance Taxes” means all extraction, production, excise, net proceeds, severance, windfall profit and all other Taxes and similar obligations, and any penalties, additions to Tax, and interest levied or assessed thereon, with respect to the Assets that are based upon or measured by the production of Hydrocarbons or the receipt of proceeds therefrom, but not including Property Taxes, Income Taxes, and Transfer Taxes.

E.    “Tax” or “Taxes” means any and all taxes, including any interest, penalties or other additions to tax, that may become payable in respect thereof, imposed by any governmental authority, which taxes shall include all income taxes, profits taxes, taxes on gains, alternative minimum taxes, estimated taxes, payroll taxes, employee withholding taxes, unemployment insurance taxes, social security taxes, welfare taxes, disability taxes, severance taxes, license charges, taxes on stock, sales taxes, harmonized sales taxes, use taxes, ad valorem taxes, value added taxes, excise taxes, goods and services taxes, franchise taxes, gross receipts taxes, occupation taxes, real or personal property taxes, land transfer taxes, stamp taxes, environmental taxes, transfer taxes, workers’ compensation taxes, windfall taxes, net worth taxes, and other taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges of the same or of a similar nature to any of the foregoing.

F.    “Transfer Taxes” means any and all transfer Taxes (excluding Income Taxes, Severance Taxes and Property Taxes), including sales, use, excise, goods and services,

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stock, conveyance, gross receipts, registration, business and occupation, securities transactions, real estate, land transfer, stamp, documentary, notarial, filing, recording, Permit, license, authorization and similar Taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges.

9.2    Apportionment of Property Taxes.

A.    The Parties acknowledge that the Converse County, Wyoming Property Taxes assessed with respect to certain of the Assets are measured by the production of Hydrocarbons (“Oil and Gas Property Taxes”). Oil and Gas Property Taxes shall be apportioned between the Parties in accordance with the relative ownership periods pre- and post-Effective Times. 2013 Oil and Gas Property Taxes, based on the value of 2013 production of Hydrocarbons and payable in 2014, shall be allocated between the Seller and Buyer in accordance with their proportionate ownership periods during 2013 before and after the Effective Time. For the purpose of calculating the Closing Amount under Section 2.4 and the Final Purchase Price under Section 13.1, 2013 Oil and Gas Property Taxes, which are determined by 2013 production and are payable in 2014 shall be estimated based on the then-current mill levies and the production occurring prior to the Effective Date with the resulting Purchase Price adjustment under Section 13.1 to be considered full and final settlement of all such Oil and Gas Property Taxes without regard to the actual Tax rates or assessments; provided that, if the actual amounts of such production and mill levies are not known at the time of the Closing, the amounts shall be re-estimated based on the best information available at the time of the Final Settlement Statement, and such estimated amounts shall thereupon become full and final settlement of such Oil and Gas Property Taxes for purposes of this Agreement.

B.    Property Taxes other than those described in clause A (“Other Property Taxes”) shall be deemed attributable to the period during which ownership of the applicable Assets gives rise to liability for such Other Property Taxes, and liability therefor allocated to Seller for all periods ending prior to the Effective Time and to Buyer for all periods beginning on or after the Effective Time. To the extent the actual amount of an Other Property Tax that is attributable to a period ending prior to the Effective Time (but not due and payable prior to the Closing) is not determinable at the time an adjustment to the Purchase Price is to be made with respect to such Other Property Tax pursuant to Section 2.4 and/or Section 13.1, as applicable, the Parties shall utilize the most recent information available in estimating the amount of such Other Property Tax for purposes of such adjustment, and the amount of such Other Property Tax used for purposes of Section 13.1 shall be considered full and final settlement of such Other Property Tax without regard to the actual Tax rates or assessments.

C.    Buyer shall be entitled to all rights to any refunds of Property Taxes allocable to Buyer pursuant to this Section 9.2 regardless of when received. Seller shall be entitled to all rights to any refunds of Property Taxes allocated to Seller pursuant to this Section 9.2. After Closing, Buyer shall timely file or cause to be filed all Tax Returns for Property Taxes required to be filed after the Closing and shall timely pay or cause to be paid to the taxing authorities all Property Taxes that become due and payable after the Closing. Any penalty, addition to Tax, or interest levied or assessed with respect to any Property Tax shall be allocated to, and shall be payable by, the Party to which the Tax to which such penalty, addition to Tax or interest relates is allocated, regardless of when such penalty, addition to Tax, or interest is levied

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or assessed; provided, however, that the liability for any penalty, addition to Tax, or interest levied or assessed with respect to any failure of Buyer to comply with the previous sentence shall be allocated to, and shall be payable by, Buyer.

9.3    Apportionment of Severance Taxes. Severance Taxes shall be deemed attributable to the period during which the production of the Hydrocarbons with respect to such Severance Taxes occurred, and liability therefor shall be allocated to Seller for pre-Effective Time Severance Taxes and to Buyer for post-Effective Time Severance Taxes. For the purpose of calculating the Closing Amount under Section 2.4 and the Final Purchase Price under Section 13.1, Severance Taxes for which the actual liability amount is not known as of such time shall be estimated based on current Wyoming Severance Tax rates, with the resulting Purchase Price adjustment under Section 13.1 to be considered full and final settlement of all such Taxes without regard to the actual Tax rates or assessments; provided that, if the actual amounts of the applicable Severance Tax rates are not known at the time of the Closing, the amounts shall be re-estimated based on the best information available at the time of the Final Closing Statement, and such estimated amounts shall thereupon become full and final settlement of such Severance Taxes for purposes of this Agreement. Buyer shall be entitled to all rights to any refunds of Severance Taxes allocable to Buyer pursuant to this Section 9.3 regardless of when received. Seller shall be entitled to all rights to any refunds of Severance Taxes allocated to Seller pursuant to this Section 9.3. After Closing, Buyer shall timely file or cause to be filed all Tax Returns for Severance Taxes required to be filed after the Closing and shall timely pay or cause to be paid to the taxing authorities all Severance Taxes that become due and payable after the Closing. Any penalty, addition to Tax, or interest levied or assessed with respect to any Severance Tax shall be allocated to, and shall be payable by, the Party to which the Tax to which such penalty, addition to Tax or interest relates is allocated, regardless of when such penalty, addition to Tax, or interest is levied or assessed; provided, however, that the liability for any penalty, addition to Tax, or interest levied or assessed with respect to any failure of Buyer to comply with the previous sentence shall be allocated to, and shall be payable by, Buyer.

9.4    Income Taxes. Each Party shall be responsible for its own Income Taxes.

9.5    Transfer Taxes. Buyer shall be liable for and shall indemnify the Seller Indemnified Parties for, any Transfer Taxes (including any related interest, penalties or legal costs) that may be imposed on any transfer of the Assets pursuant to this Agreement. If required by applicable law, Seller shall, in accordance with applicable law, calculate and remit any Transfer Taxes that are required to be paid as a result of the transfer of the Assets to Buyer and Buyer shall promptly reimburse Seller therefor. If Seller receives notice that any Transfer Taxes are due, Seller shall promptly forward such notice to Buyer for handling.

9.6    Post-Closing Tax Matters. After the Closing, each of Buyer and Seller shall:

A.    reasonably cooperate and assist the other (i) in preparing any Tax Returns relating to any Tax the Assets or imposed, or the Transaction, and (ii) in qualifying for any exemption or reduction in Tax that may be available;

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B.    reasonably cooperate in preparing for any audits, examinations or other tax proceedings by, or disputes with, taxing authorities regarding any Tax relating to the Assets or the Transaction;

C.    make available to the other, and to any taxing authority as reasonably requested, any information, records, and documents relating to a Tax incurred or imposed in connection with the Assets or the Transaction;

D.    provide timely notice to the other in writing of any pending or threatened Tax audit, examination, or assessment that could reasonably be expected to affect the other’s Tax liability under applicable law or this Agreement (a “Tax Controversy”), and to promptly furnish the other with copies of all correspondence with respect to any Tax Controversy; and

E.    allow the other to participate, at its own expense, in any Tax Controversy, and not settle any Tax Controversy without the prior written consent of the other, which may not be unreasonably withheld, conditioned or delayed.

9.7    Allocations for Federal Income Tax Purposes. Buyer and Seller acknowledge that, under Section 1060 of the Code, Buyer and Seller must report information regarding the allocation of the Purchase Price and any other amounts treated as consideration for federal income tax purposes (collectively, the “Allocation Amount”) to the United States Secretary of Treasury by attaching Department of Treasury, Internal Revenue Service, Form 8594 to their federal income tax returns for the tax period which includes the Closing Date. Buyer and Seller agree that the “Allocation Amount” shall be allocated among the Assets for Tax purposes in accordance with an allocation schedule that will be prepared and mutually agreed upon by the Parties prior to the Final Settlement Date (the “Tax Allocation Schedule”), in a manner consistent with Section 1060 of the Code to take into account any adjustments to the Purchase Price pursuant to this Agreement, including any indemnification payments pursuant to Article 14. Buyer and Seller shall each prepare their respective Forms 8594 with respect to transactions contemplated by this Agreement in a manner consistent with the Tax Allocation Schedule. The Parties shall not take any income tax position (whether in audits, on tax returns, or otherwise) that is inconsistent with such allocation unless required to do so by applicable law. Any dispute regarding the Tax Allocation Schedule will be determined by the Accounting Arbitrator pursuant to Section 13.1B.

ARTICLE 10.

CONDITIONS PRECEDENT TO CLOSING

10.1    Seller’s Conditions Precedent. The obligations of Seller at the Closing are subject, at the option of Seller, to the satisfaction or waiver at or prior to the Closing of the following conditions precedent:

A.    All representations and warranties of Buyer contained in this Agreement are true in all material respects (for this purpose any materiality qualifier in such representations and warranties will be ignored) at and as of the Closing in accordance with their terms as if such representations and warranties were remade at and as of the Closing, other than for representations and warranties that refer to a specified date, which need only be true on and as of

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the specified date. Buyer has performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing in all material respects;

B.    No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits this Transaction and that remains in effect at the time of Closing;

C.    Union Bank, N.A. shall have consented to the Transaction and shall have released any liens it may hold against the Assets;

D.    Helis Oil & Gas Company, L.L.C. (“Helis”) and Samson Resources Corporation (“Samson”) shall have consented to the Seller’s assignment to Buyer of that certain Leasehold Purchase and Exploration Agreement dated November 1, 2009 by and between Seller, Ballard Petroleum Holdings LLC, and Helis, as amended from time to time (as so amended, the “Helis Agreement”); and

E.    No Material Adverse Effect shall have occurred and still be outstanding.

10.2    Buyer’s Conditions Precedent. The obligations of Buyer at the Closing are subject, at the option of Buyer, to the satisfaction or waiver at or prior to the Closing of the following conditions precedent:

A.    All representations and warranties of Seller contained in this Agreement are true in all material respects (for this purpose any materiality qualifier in such representations and warranties will be ignored) at and as of the Closing in accordance with their terms as if such representations and warranties were remade at and as of the Closing, other than for representations and warranties that refer to a specified date, which need only be true on and as of the specified date. Seller has performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Seller at or prior to the Closing in all material respects;

B.    No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits this Transaction and that remains in effect at the time of Closing;

C.    Except as provided in Section 4.7, Seller has delivered to Buyer all Required Consents other than any required governmental approvals that are the type of Required Consent ordinarily obtained post-Closing;

D.    Union Bank, N.A. shall have consented to the Transaction and shall have released any liens it may hold against the Assets; and

E.    Helis and Samson shall have consented to the assignment of the Helis Agreement.

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F.    Ballard Petroleum Holdings LLC shall be ready, willing and able to Close under that certain Purchase and Sale Agreement entered into contemporaneously herewith, by and between Ballard Petroleum Holdings LLC, as seller, and Buyer.

G.    No Material Adverse Effect shall have occurred and still be outstanding.

ARTICLE 11.

Termination

11.1    Termination. This Agreement may be terminated in accordance with the following provisions:

A.    by Seller, at Seller’s option, if any of the conditions set forth in Section 10.1 have not been satisfied on or before March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), through no fault of Seller or are not waived by Seller, as of March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), provided that in the case of a failure of only the condition under Section 10.1A, the condition remains unsatisfied for five (5) business days following written notice thereof from Seller to Buyer specifying the reason such condition is unsatisfied (including any breach by Buyer of this Agreement);

B.    by Buyer, at Buyer’s option, if any of the conditions set forth in Section 10.2 have not been satisfied on or before March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), through no fault of Buyer, or are not waived by Buyer, as of March 6, 2013 (or such other date set for Closing pursuant to Section 12.1), provided that in the case of a failure of only the condition under Section 10.2A, the condition remains unsatisfied for five (5) business days following written notice thereof from Buyer to Seller specifying the reason such condition is unsatisfied (including any breach by Seller of this Agreement);

C.    by Buyer or Seller, upon notice to the other given prior to Closing, if the aggregate of the Title and Environmental Defects Adjustment and the Exclusion Adjustments exceed ten percent (10%) of the Purchase Price;

D.    by either Party if Closing shall not have occurred on or before May 6, 2014; or

E.    upon the Parties’ mutual agreement;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to Paragraph A through D above if such Party is at such time in material breach of any provision of this Agreement. Except as provided in Section 11.2A, if a Party has rightfully terminated this Agreement, then the Deposit shall be promptly returned to Buyer, but in any event, within three (3) business days of such termination.

11.2    Remedies.

A.    Buyer’s Breach. If Closing does not occur because Buyer wrongfully fails to tender performance at Closing or otherwise is in material breach of this Agreement prior to

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Closing, and Seller is not in material breach of this Agreement and is ready and otherwise able to close, Seller shall retain the Deposit, and Seller may terminate this Agreement and keep the Deposit, which shall constitute liquidated damages hereunder, and which remedy shall be the sole and exclusive remedy available to Seller for any such failure of Buyer. The Parties acknowledge that (i) Seller’s actual damages upon such termination are difficult to ascertain, (ii) the liquidate damages set forth in the proceeding sentence is a reasonable estimate by the Parties of such actual damages to Seller, and (iii) such liquidated damages do not constitute a penalty. Buyer’s failure to tender performance at Closing shall not be considered wrongful if all of the conditions set forth in Section 10.2 have not been satisfied.

B.    Seller’s Breach. If Closing does not occur because Seller wrongfully fails to tender performance at Closing or otherwise is in material breach of this Agreement prior to Closing, and Buyer is not in material breach of this Agreement and is ready and otherwise able to close, Seller shall return the Deposit within three (3) business days, and Buyer may terminate this Agreement or pursue all legal and equitable remedies for Seller’s breach of this Agreement and Seller’s wrongful failure to close (excluding special, consequential, punitive or exemplary damages or loss of profits), including an action for specific performance. Seller’s failure to tender performance at Closing shall not be considered wrongful if all of the conditions set forth in Section 10.1 have not been satisfied.

C.    Effect of Termination. If this Agreement is terminated as provided in Section 11.1 or Section 11.2, then this Agreement shall be of no further force and effect and the Parties have no liability or obligation under this Agreement except for (i) the provisions of this Agreement which expressly survive termination of this Agreement, and (ii) the provisions of this Agreement relating to the retention or return of the Deposit, Section 6.2, Section 7.2, Section 8.3A, Section 8.3B, Section 8.3C, Section 14.14, Article 15, and such defined terms as set forth in this Agreement to give context to the provisions of this Agreement which survive termination under this Section 11.2C, all of which shall continue in full force and effect.

ARTICLE 12.

Closing

12.1    Date of Closing. The “Closing” of this Transaction shall be held on March 6, 2014, at 10:00 a.m. or such other date and time selected by mutual agreement of the Parties in writing. Upon execution of this Agreement, Buyer shall immediately commence its due diligence with respect to the environmental condition of the Assets, pursuant to Section 3.3 and Section 5.2, and shall use commercially reasonable efforts to complete such environmental due diligence prior to February 28, 2014. In the event that Buyer, despite its commercially reasonable efforts, due to snow cover or other adverse weather conditions, is unable to complete its onsite inspections or environmental assessments of the Assets (the uncompleted portion referred to as the “Outstanding Environmental Diligence”) on or before February 28, 2014, Buyer may, in its sole discretion, by written notice to Seller delivered on or before February 28, 2014 (an “Extension Notice”), elect to extend Closing to the date set forth in the Extension Notice, but in no event later than May 6, 2014. At the time Seller delivers the Extension Notice, Buyer will deliver to Seller a list of the Outstanding Environmental Diligence. In the event Buyer elects to extend Closing as set forth in the preceding sentence, Buyer shall use commercially reasonable efforts to complete the Outstanding Environmental Diligence and close

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as soon as possible, but in any event, on or before May 6, 2014. If Buyer has so elected to extend the Closing, Closing will take place on the tenth (10th) business day after Buyer has completed the Outstanding Environmental Diligence, but in no event later than May 6, 2014. The date the Closing actually occurs is called the “Closing Date”.

12.2    Place of Closing. The Closing shall be held at Buyer’s office in Denver, Colorado, or at such other place as Buyer and Seller may agree in writing.

12.3    Closing Obligations. At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

A.    Seller shall execute, acknowledge and deliver to Buyer (a) an Assignment, Bill of Sale, and Conveyance in the form attached as Exhibit E (the “Assignment”) conveying the Assets to Buyer as of the Effective Time, and (b) such other assignments or transfers necessary to convey the Assets to Buyer, including without limitation, any conveyances on official forms and related documentation necessary to transfer the Assets to Buyer in accordance with governmental regulation;

B.    Buyer shall deliver the Closing Amount to the account at the bank designated by Seller in the Preliminary Settlement Statement or other notice by wire transfer in immediately available funds, or by such other method as agreed to by the Parties;

C.    Seller shall execute and deliver to Buyer an affidavit of non-foreign status and no requirement for withholding under Section 1445 of the Code in the form attached as Exhibit F.

D.    Seller shall execute and deliver to Buyer an Officer’s Certificate, dated as of the Closing Date, in form and substance as set forth in Exhibit G;

E.    Buyer shall execute and deliver to Seller an Officer’s Certificate, dated as of the Closing Date, in form and substance as set forth in Exhibit H;

F.    Seller shall deliver the Records to Buyer, at Buyer’s expense, at Buyer’s Denver, Colorado offices within ten (10) business days after the Closing;

G.    Seller shall deliver to Buyer all Required Consents obtained as of Closing other than required governmental approvals ordinarily obtained post-Closing;

H.    Seller shall deliver and Seller and Buyer shall execute and deliver letters in lieu of transfer orders; and

I.    Seller and Buyer shall take such other actions and deliver such other documents as are contemplated by this Agreement.

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ARTICLE 13.

Post-Closing Obligations

13.1    Final Settlement Statement.

A.    On or before one hundred and twenty (120) days after the Closing Date (“Final Settlement Statement Due Date”), Seller will prepare and deliver to Buyer a “Final Settlement Statement” setting forth each adjustment or payment that was not finally determined as of the Closing, and showing the calculation of such adjustment and the resulting final purchase price (the “Final Purchase Price”). On or before thirty (30) days after receipt of Seller’s proposed Final Settlement Statement, Buyer shall deliver to Seller a written report containing Buyer’s proposed changes to the Final Settlement Statement. Buyer’s failure to deliver to Seller a written report detailing proposed changes to the Final Settlement Statement by that date shall be deemed an acceptance by Buyer of the Final Settlement Statement as submitted by Seller. The Parties shall attempt to agree with respect to the changes proposed by Buyer, no later than five (5) days after receipt of Buyer’s suggested changes to the Final Settlement Statement (the “Dispute Resolution Date”). If the Parties are unable to agree Section 13.1B will apply. The date upon which such agreement is reached or upon which the Final Purchase Price is established, as provided in Section 13.1B, shall be herein called the “Final Settlement Date.” If the Final Purchase Price is more or less than the sum of the Closing Amount plus the Deposit, Buyer or Seller shall make the appropriate payments by wire transfer in same day funds to the appropriate Party, without interest, within ten (10) days of the Final Settlement Date.

B.    If Seller and Buyer are unable to resolve the matters with respect to Buyer’s proposed changes by the Dispute Resolution Date, each of Buyer and Seller shall within ten (10) business days after the Dispute Resolution Date, summarize its position with regard to such dispute in a written document of twenty (20) pages or less and submit such summaries to such person as the Parties may mutually select (the “Accounting Arbitrator”), together with Buyer’s proposed changes, the Final Settlement Statement and any other documentation such Party may desire to submit. Within ten (10) business days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and enforceable against any of the Parties in any court of competent jurisdiction. The costs of the Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller. If the parties are unable to agree upon the Accounting Arbitrator within ten (10) business days after the Dispute Resolution Date, then either Party may apply to the Eighth Judicial District Court in and for Converse County, Wyoming for the appointment of an arbitrator pursuant to the Wyoming Uniform Arbitration Act, Wyo. Stat. § 1-36-101, et seq.

C.    If after the delivery of the Final Settlement Statement pursuant to the provisions of Section 13.1A (i) either Party receives monies (including proceeds of production) belonging to the other Party pursuant to Section 1.6 or otherwise, then such monies shall, within five (5) business days after the end of the month in which they were received, be paid over by the receiving Party to the owed Party, (ii) either Party pays monies for Property Expenses that are the obligation of the other Party pursuant to Section 1.6 or otherwise, then the obligated Party shall, within five (5) Business Days after the end of the month in which the applicable invoice

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and proof of payment of such invoice are received by it, reimburse the paying Party therefor, (iii) either Party receives an invoice of an expense or obligation that is owed by the other Party pursuant to Section 1.6 or otherwise, then the receiving Party shall promptly forward such invoice to the obligated Party and (iv) if an invoice of an expense or other obligation is received by either Party and is the obligation of both Parties, then the Parties shall consult with each other and shall each promptly pay its portion of such invoice to the obligee. Each Party shall be permitted to offset any monies owed by it to the other Party pursuant to this Section 13.1C against amounts owing by it to such other Party pursuant to this Section 13.1C.

13.2    Financial Statements. Seller acknowledges that Buyer and its affiliates may be required to include statements of revenues and direct operating expenses and other financial information relating to the Transaction in documents filed by Buyer and its affiliates with the Securities Exchange Commission (the “SEC”) pursuant to the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and that such financial statements may be required to be audited. Accordingly, but subject to (y) those items that are excluded to arrive at the definition of Records, and (z) items that are Excluded Assets, from and after the date of execution of this Agreement, Seller shall use commercially reasonable efforts to (a) promptly provide Buyer with such information about the Assets that is in Seller’s possession or is provided to Seller by an Operator and that is reasonably requested by Buyer on the grounds that it is required to be included in documents filed by Buyer and its affiliates with the SEC, (b) provide, and shall cause its affiliates, officers and employees to provide, reasonable cooperation in connection with the Buyer’s preparation of documents to be filed by Buyer and its affiliates with the SEC, including providing reasonable access to employees, books and records and any existing financial data relating to the Assets that is reasonably requested by Buyer in connection with such filings with the SEC, and (c) request that Operators provide information and documents that Seller is entitled by Contract to receive and that is reasonably requested by Buyer in connection with such filings with the SEC; provided, however, that Seller shall not be required under this Section 13.2 to prepare or cause to be prepared any new reports, documents or financial data relating to the Assets.

13.3    Area of Mutual Interest. If, during the period of time from the Closing Date until two (2) year after the Closing Date, Seller, or any if its affiliates, representatives, agents, partners, successors or assigns (collectively a “Seller Party”) shall lease, purchase, trade, or otherwise acquire, either directly or indirectly any oil and gas lease, leasehold rights, mineral interest or development rights (including entering into any farmout or participation agreement) covering lands within the Transaction Area, such Seller Party shall immediately notify Buyer of such acquisition in writing, and within fourteen (14) days thereof, at Buyer’s option, exercisable in its sole discretion, such Seller Party shall assign 100% of such interest to Buyer, at such Seller Party’s actual cost, free and clear of any overriding royalties, leasehold burdens, liens or other encumbrances placed thereon by such Seller Party, pursuant to an assignment substantially in the form of Exhibit E, containing a special warranty of title by, through and under such Seller Party, but not otherwise. This Section 13.3 shall not apply to Seller’s ownership, use and development of any of the Excluded Assets.

13.4    Further Assurances. From time to time after Closing, the Parties shall each execute, acknowledge and deliver to the other such further instruments and take such other

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action as may be reasonably requested in order to accomplish more effectively the purposes of the Transaction.

ARTICLE 14.

Assumption and Retention of Obligations and Indemnification

14.1    Buyer’s Assumption of Liabilities and Obligations. From and after Closing, and except for Retained Liabilities, Buyer shall assume and pay, perform, fulfill, and discharge: (a) all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to its owning, developing, exploring, or maintaining of the Assets or the producing, transporting, and marketing of Hydrocarbons from the Assets for the periods after the Effective Time, or, in the case of Taxes, to the extent apportioned pursuant to Article 9 to the period of time after the Effective Time; (b) all obligations of Seller arising under the Leases and Contracts after the Effective Time (except as otherwise provided in this Agreement); (c) the Assumed Environmental Liabilities; (d) furnishing of makeup gas and settlements of imbalances according to the terms of applicable gas sales, processing, gathering and transportation contracts; and (e) payment of royalties, overriding royalties, net profit interests or other interests or obligations attributable to the sales of Hydrocarbons after the Effective Time, (f) the payment of those amounts held in suspense for which the Purchase Price was adjusted pursuant to Section 2.4 whether attributable to the period before or after the Effective Time and (g) the Special Obligations (as later defined, but substituting Buyer in the place of any reference to Seller) to the extent attributable to the period of time after Closing (collectively, the “Assumed Liabilities”).

14.2    Seller’s Retention of Liabilities and Obligations.

A.    From and after Closing, and except for the Assumed Liabilities, Seller retains and agrees to continue to be liable to perform, fulfill and discharge all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to its owning, developing, exploring or maintaining of the Assets prior to the Effective Time, or, in the case of Taxes, to the extent apportioned pursuant to Article 9, to the period of time prior to the Effective Time.

B.    From and after Closing and except for the Assumed Liabilities, Seller retains and agrees to continue to be liable to perform, fulfill and discharge all claims, costs, expenses, liabilities, Losses and obligations accruing or relating to (i) any injury, death, casualty, tortious action or inaction occurring on or attributable to the Assets; (ii) employee-related claims of Seller; (iii) obligations with respect to the payment or mis-payment of royalties, overriding royalties, net profits interests or other interests or obligations attributable to the sale of Hydrocarbons; and (iv) Taxes (the “Special Obligations”), in each case attributable to the period of time prior to Closing.

C.    From and after Closing, Seller retains and agrees to perform, fulfill and discharge all claims, costs, expenses, liabilities, Taxes, and obligations accruing or relating to the owning, developing, exploring or maintaining of the Excluded Assets before or after the Effective Time.

D.    To the extent the Assets are or may be deemed to be “securities” under the Securities Act of 1933, as amended, and certain applicable state securities or Blue Sky laws

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and that resales thereof may therefore be subject to the registration requirements of such acts, Seller shall retain any and all liability for Losses attributable to representations made to its investors.

The liabilities set forth in Section 14.2A, Section 14.2B, Section 14.2C and Section 14.2D are, collectively, the “Retained Liabilities.”

14.3    Indemnification. “Losses” shall mean any actual losses, costs, expenses (including court costs, reasonable fees and expenses of attorneys, technical experts and expert witnesses and the cost of investigation), liabilities, damages, demands, suits, claims, and sanctions of every kind and character (including civil fines) arising from, related to or reasonably incident to matters indemnified against.

After the Closing, the Parties shall indemnify each other as follows:

A.    Seller’s Indemnification of Buyer. Seller assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Buyer, its officers, directors, shareholders, partners, members, affiliates, employees, agents, and successors and assigns (“Buyer Indemnified Parties”), from and against any and all Losses and causes of action, liabilities and expenses relating to, or arising out of, or connected, directly or indirectly, with the Retained Liabilities, and any breach of the Seller’s representations, warranties and covenants under this Agreement.

B.    Buyer’s Indemnification of Seller. Buyer assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Seller, its officers, directors, employees, shareholders, partners, members, affiliates, agents, and successors and assigns (“Seller Indemnified Parties”) from and against any and all Losses and causes of action, liabilities and expenses relating to, or arising out of or connected, directly or indirectly, with the Assumed Liabilities and any breach of the Buyer’s representations, warranties and covenants under this Agreement.

C.    Release.Buyer shall be deemed to have released Seller at the Closing from any Losses for which Buyer has agreed to indemnify Seller hereunder, and Seller shall be deemed to have released Buyer at the Closing from any Losses for which Seller has agreed to indemnify Buyer hereunder. The releases in the preceding sentence shall extend to each Party’s respective officers, directors, shareholders, partners, members, representatives, employees, agents and affiliates.

14.4    Indemnification Limitations.

A.    Neither Seller nor Buyer shall not have any liability for any indemnifications under Section 14.3A or Section 14.3B for any Loss (without duplication) arising from a single event unless the amount with respect to such Loss exceeds Twenty-Five Thousand Dollars ($25,000.00) (the “Individual Indemnity Threshold”) anduntil and unless the aggregate amount of all Losses exceeding the Individual Indemnity Threshold and for which Claim Notices are delivered by the Indemnified Party prior to expiration of the applicable period under Section 14.8 exceeds Two Hundred and Fifty Thousand Dollars ($250,000.00) (the “Indemnity Deductible”), and then only to the extent such Losses exceed the Indemnity

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Deductible. Notwithstanding anything to the contrary contained in this Agreement, Seller and Buyer shall not be required to indemnify the other Party for aggregate Losses in excess of twenty percent (20%) of the Purchase Price (the “Indemnity Cap”).

B.    Notwithstanding the foregoing, (i) Seller’s obligation to indemnify Buyer for those Retained Liabilities set forth in Section 14.2B or Section 14.2C, (ii) Buyer’s obligation to indemnify Seller for those Assumed Liabilities set forth in Section 14.1(g), or, Section 14.1(c), but only with respect to any Claim asserted by delivery of a Claim Notice with respect to Section 14.1(c) on or before twenty four (24) months after the Closing Date, and (iii) either Party’s breach of the Special Representations, or any covenant or agreement contained in this Agreement, shall not be limited by Section 14.4A, and the obligation to indemnify shall be from the first dollar of any Loss, and without regard to the Individual Indemnity Threshold, the Indemnity Deductible and the Indemnity Cap.

14.5    Express Negligence. EXCEPT AS OTHERWISE PROVIDED IN SECTION 3.3, THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE AND ASSUMED OBLIGATIONS PROVISIONS PROVIDED IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LOSSES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, EXCLUDING HOWEVER THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS “CONSPICUOUS.”

14.6    Exclusive Remedy. Except for causes of action based on actual fraud or willful misconduct, notwithstanding anything to the contrary contained in this Agreement, the Parties agree that, from and after Closing, the Assignment, Section 1.7, Section 3.3, Section 4.2B, Section 4.5, Section 4.9, Section 5.4D, Section 5.5, Section 8.3C, Section 13.1A, Section 13.1B, Section 14.3A, Section 14.3B and Section 15.12 contain the Parties’ exclusive remedies against each other with respect to the Transaction, including breaches of representation, warranties, covenants and agreements of the Parties contained in this Agreement or in any document or certificate delivered pursuant to this Agreement.

14.7    Procedure. The indemnifications contained in this Article shall be implemented as follows:

A.    Claim Notice. The Party seeking indemnification under the terms of this Agreement (“Indemnified Party”) shall submit a written “Claim Notice” to the other Party (“Indemnifying Party”) which shall list the amount claimed by an Indemnified Party, the basis for such claim, with supporting documentation, and list each separate item of Loss for which payment is so claimed. The amount claimed shall be paid by the Indemnifying Party to the extent required herein within thirty (30) days after receipt of the Claim Notice, or after the amount of such payment has been finally established, whichever last occurs.

B.    Information. If the Indemnified Party receives notice of a claim or legal action that may result in a Loss for which indemnification may be sought under this Agreement

46

(a “Claim”), the Indemnified Party shall give written notice of such Claim to the Indemnifying Party as soon as is practicable. If the Indemnifying Party or its counsel so requests, the Indemnified Party shall furnish the Indemnifying Party with copies of all pleadings and other information with respect to such Claim. At the election of the Indemnifying Party made within sixty (60) days after receipt of such notice, the Indemnified Party shall permit the Indemnifying Party to assume control of such Claim (to the extent only that such Claim, legal action or other matter relates to a Loss for which the Indemnifying Party is liable), including the determination of all appropriate actions, the negotiation of settlements on behalf of the Indemnified Party, and the conduct of litigation through attorneys of the Indemnifying Party’s choice; provided, however, that any settlement of the claim by the Indemnifying Party may not result in any liability or cost to the Indemnified Party without its prior written consent. If the Indemnifying Party elects to assume control, (i) any expense incurred by the Indemnified Party thereafter for investigation or defense of the matter shall be borne by the Indemnified Party, and (ii) the Indemnified Party shall give all reasonable information and assistance, other than pecuniary, that the Indemnifying Party shall deem necessary to the proper defense of such Claim. In the absence of such an election, the Indemnified Party will use its best efforts to defend, at the Indemnifying Party’s expense, any claim, legal action or other matter to which such other Party’s indemnification under this Article 14 applies until the Indemnifying Party assumes such defense. If the Indemnifying Party fails to assume such defense within the time period provided above, the Indemnified Party may settle the Claim, in its reasonable discretion at the Indemnifying Party’s expense. An Indemnifying Party (or the Indemnified Party if the Indemnified Party is defending the Claim) shall not, without the written consent of the other Party, (i) settle any Claim or consent to the entry of any judgment with respect to the Claim which does not include an unconditional written release of the Indemnified Party or the Indemnifying Party, as the case may be, from all liability in respect of such Claim, or (ii) settle any Claim or consent to the entry of any judgment with respect to the Claim in any manner that may materially or adversely affect the Indemnified Party or the Indemnified Party, as the case may be (other than as a result of money damages covered by the indemnity). If such a Claim requires immediate action, both the Indemnified Party and the Indemnifying Party will cooperate in good faith to take appropriate action so as not to jeopardize defense of such Claim or either Party’s position with respect to such Claim.

14.8    Survival.

A.    Except as provided in Section 14.8B, a Party’s representations, warranties, covenants or agreements under this Agreement will survive the Closing or terminate at the Closing (in each case, the “Survival Period”):

(a)    Except as provided in Paragraphs (b), (c), (d) and (e), all representations and warranties will survive the Closing until 5:00 o’clock p.m. prevailing Mountain Time twelve (12) months after the Closing Date;

(b)    The representations and warranties set forth in Section 5.3 will survive the Closing until 5:00 o’clock p.m. prevailing Mountain Time twelve (12) months after the Closing Date;

47

(c)    The following representations and warranties will survive the Closing until the expiration of the applicable Statute of Limitations: Sections 6.1A, 6.1B, 6.2, 6.3, 6.4, 6.5, 6.6, 7.1A, 7.1B, 7.2, 7.3, 7.8, and 7.9 (the “Special Representations”);

(d)    All of the covenants, agreements, disclaimers and releases contained in this Agreement will survive the Closing in accordance with their terms.

Representations and warranties shall be of no further force and effect after the end of the respective Survival Period; provided that there shall be no termination of any bona fide Claim asserted pursuant to this Agreement by the delivery of a Claim Notice with respect to such representation or warranty prior to end of the respective Survival Period.

B.    The indemnities contained in this Agreement, including under Section 1.7, Section 3.3, Section 9.3, Section 14.3A and Section 14.3B, shall survive Closing until expiration of the applicable Statute of Limitations, and shall be of no further force and effect thereafter, except with respect to any bona fide Claim asserted pursuant to this Agreement by delivery of a Claim Notice with respect to such indemnification prior to its expiration date.

14.9    Insurance. The amount of any Losses for which any of the Buyer Indemnified Parties or the Seller Indemnified Parties, as applicable, is entitled to indemnification under this Agreement or in connection with or with respect to the Transaction shall be reduced by any corresponding insurance proceeds from insurance policies carried by the Buyer Indemnified Party or Seller Indemnified Party, as applicable, if a claim were properly pursued under the relevant insurance arrangements (net of any collection costs).

14.10    No Insurance; Subrogation. The indemnifications provided in this Agreement shall not be construed as a form of insurance. Buyer and Seller hereby waive for themselves, their respective successors or assigns, including, without limitation, any insurers, any rights to subrogation for Losses for which each of them is respectively liable or against which each respectively indemnifies the other, and, if required by applicable policies, Buyer and Seller shall obtain waiver of such subrogation from their respective insurers.

14.11    Reservation as to Non-Parties. Nothing herein is intended to limit or otherwise waive any recourse Buyer or Seller may have against any non-Party for any obligations or liabilities that may be incurred with respect to the Assets.

14.12    Noncompensatory Damages. None of the Buyer Indemnified Parties nor Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, as applicable, or their respective affiliates, any loss of profits, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising under or in connection with the Agreement or the Transaction, except to the extent any such Party is liable for such damages to a third party. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Indemnified Parties and Seller, on behalf of each of the Seller Indemnified Parties, each waive any right to recover any loss of profit, special, indirect, consequential, punitive, exemplary, remote or speculative damages arising in connection with or with respect to this Agreement or the Transaction.

48

14.13    Disclaimer of Application of Anti-Indemnity Statutes. The Parties acknowledge and agree that the provisions of Wyo. Stat. § 30-1-131 relating to oilfield services and associated activities shall not be applicable to this Agreement or the Transaction.

ARTICLE 15.

Miscellaneous

15.1    Expenses. All fees, costs, and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating this Transaction shall be paid by the Party incurring the same including, without limitation, engineering, land, title, legal and accounting fees, costs and expenses.

15.2    Notices. All notices and communications required or permitted under this Agreement shall be in writing and addressed as set forth below. Any communication or delivery hereunder shall be deemed to have been made and the receiving Party charged with notice when received whether by: (i) personal delivery; (ii) mail (provided that a Party will be deemed to have received notice mailed by registered or certified mail five (5) days after mailing); or (iii) overnight courier. All notices shall be addressed as follows:

Seller

Maurice W. Brown Oil & Gas, LLC

516 South Greeley Highway

Cheyenne, Wyoming 82007

Attention: Robert McCue

Telephone: 307-634-8605

Buyer

Fidelity Exploration & Production Company

1700 Lincoln Avenue, Suite 2800

Denver, Colorado 80203

Attention: Darrell Finneman

Telephone: 303-893-3133

Fidelity Oil Co.

1700 Lincoln Avenue, Suite 2800

Denver, Colorado 80203

Attention: Darrell Finneman

Telephone: 303-893-3133

A Party may, by written notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made.

15.3    Relationship of Buyer Entities. It is not the intention of the Fidelity Exploration or Fidelity Oil to create a partnership, joint venture, mining partnership or association among such entities, and neither this Agreement nor the ownership of the Assets by Fidelity Exploration

49

and Fidelity Oil after Closing as co-tenants shall be construed as creating such a relationship. The liability of Fidelity Exploration and Fidelity Oil under this Agreement shall be several and separate, not joint or collective.

15.4    Amendments/Waiver. Except for waivers specifically provided for in this Agreement, this Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the Party claiming the benefit of such amendment or waiver.

15.5    Assignment. This Agreement may not be assigned by Buyer without prior written consent of Seller.

15.6    Announcements. Except as may be required by applicable laws or the applicable rules and regulations of any governmental agency or stock exchange, Seller and Buyer shall consult with each other with regard to all press releases and other announcements issued concerning this Agreement or this Transaction, and Buyer or Seller shall not issue any such press release or other publicity without the prior written consent of the other Party, which consent shall not be unreasonably withheld.

15.7    Counterparts/Electronic Fax Signatures. Buyer and Seller may execute this Agreement in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute but one and the same instrument. The Parties agree that facsimile signatures and signatures transmitted by electronic mail are binding.

15.8    Governing Law. This Agreement and this Transaction and any dispute resolution conducted pursuant hereto shall be construed in accordance with, and governed by, the laws of the State of Wyoming.

15.9    Entire Agreement. This Agreement constitutes the entire understanding among the Parties, their respective members, shareholders, officers, directors and employees with respect to the subject matter hereof, superseding all written or oral negotiations and discussions, and prior agreements and understandings relating to such subject matter. Each Exhibit and Schedule attached to this Agreement is incorporated into this Agreement.

15.10    Knowledge. The term “knowledge” shall mean, for purposes of this Agreement, the actual, conscious knowledge, after reasonable due inquiry, (i) in the case of Seller, Maurice W. Brown or Robert McCue or the respective manager level personnel responsible for land, legal and environmental matters, and (ii) in the case of Buyer, Darrell Finneman or Patrick Rutty.

15.11    Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties hereto and their respective successors and permitted assigns, but only those persons that will have responsibilities pursuant to this Agreement are Parties to this Agreement. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, express or implied, is intended to confer on any person or entity other than the Parties or their successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder, any rights, remedies, obligations or liabilities under or by reason of this Agreement.

50

15.12    Dispute Resolution. Before commencing litigation regarding any dispute arising under this Agreement, other than any dispute covered by the dispute resolution procedures under Section 4.5, Section 5.5 or Section 13.1B, the provisions of this Section 15.11 shall apply. Each Party agrees to notify the other Party, in writing, of any such dispute.  The Parties shall then, acting in good faith, use commercially reasonable efforts to resolve the dispute as soon as possible.  If the dispute is not resolved within thirty (30) days after notice is given, then the dispute will be referred to members of senior management of each of the Parties for resolution and each Party will appoint a senior officer with the authority to settle the dispute. The senior officers so appointed will attempt to resolve the dispute within a further period of thirty (30) days from the date such referral notice is given.  If the Parties are unable to resolve the dispute within thirty (30) days of such notice, the Parties agree to endeavor to resolve the dispute through mediation.  The Parties agree to utilize good faith in selecting a mediator, scheduling the mediation and participating in the mediation.  Expenses of the mediation, excluding legal fees, shall be divided equally between the Parties.  If the dispute is not resolved through mediation, despite the Parties good faith efforts, either Party may initiate litigation within the State or Federal courts located within the State of Wyoming to resolve the dispute. Nothing in this Section 15.11 shall prevent either Party from seeking interim injunctive relief in the State or Federal courts, to maintain the status quo and avoid irreparable injury pending the outcome of the dispute resolution procedures set forth in this Section 15.11.

15.13    References, Titles and Construction

.

A.    All references in this Agreement to articles, sections, subsections and other subdivisions refer to corresponding articles, sections, subsections and other subdivisions of this Agreement unless expressly provided otherwise.

B.    Titles appearing at the beginning of any of such subdivisions are for convenience only and shall not constitute part of such subdivisions and shall be disregarded in construing the language contained in such subdivisions.

C.    The words “this Agreement,” “this instrument,” “herein,” “hereof,” “hereby,” “hereunder,” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited.

D.    Words in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Pronouns in masculine, feminine, and neutral genders shall be construed to include any other gender.

E.    Unless the context otherwise requires or unless otherwise provided herein, the terms defined in this Agreement which refer to a particular agreement, instrument or document also refer to and include all renewals, extensions, modifications, amendments or restatements of such agreement, instrument or document, provided that nothing contained in this Article shall be construed to authorize such renewal, extension, modification, amendment or restatement.

F.    Examples shall not be construed to limit, expressly or by implication, the matter they illustrate.

51

G.    The word “or” is not intended to be exclusive and the word “includes” and its derivatives mean “includes, but is not limited to” and corresponding derivative expressions.

H.    No consideration shall be given to the fact or presumption that one party had a greater or lesser hand in drafting this Agreement.

I.    All references herein to “$” or “dollars” shall refer to U.S. Dollars.

J.    References in this Agreement to a “business day” shall mean a day, other than a Saturday or Sunday, on which national banks are open for business in the State of Wyoming. If the date for a performance under this Agreement falls on a day that is not a business day, the date for such performance will be extended to the next business day.

K.    References in this Agreement to use “commercially reasonable efforts” or to “reasonably cooperate” or phrases of similar import shall not be interpreted to require the expenditure of any funds or the incurrence of any obligations.

52

IN WITNESS WHEREOF, this Agreement has been duly executed this Agreement effective as of the Effective Time.

SELLER:
MAURICE W. BROWN OIL & GAS LLC
By:	/s/ Maurice W. Brown
	Name: Maurice W. Brown
	Title: Manager

BUYER:
FIDELITY EXPLORATION & PRODUCTION
COMPANY
By:	/s/ Patrick M. Rutty
	Name: Patrick M. Rutty
	Title: Vice President of Exploration

FIDELITY OIL CO.
By:	/s/ Darwin Subart
	Name: Darwin Subart
	Title: Chief Financial Officer

53

EX-12

MDU RESOURCES GROUP, INC.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Twelve Months Ended March 31, 2014				Year Ended December 31, 2013
	(In thousands of dollars)
Earnings Available for Fixed Charges:
Net Income (a)		$	279,426			$	281,163
Income Taxes		136,673				136,736
		416,099				417,899
Rents (b)		16,619				16,035
Interest (c)		92,609				92,481
Total Earnings Available for Fixed Charges		$	525,327			$	526,415
Preferred Dividend Requirements		$	685			$	685
Ratio of Income Before Income Taxes to Net Income		149		%		149		%
Preferred Dividend Factor on Pretax Basis		1,021				1,021
Fixed Charges (d)		108,929				107,892
Combined Fixed Charges and Preferred Stock Dividends		$	109,950			$	108,913
Ratio of Earnings to Fixed Charges		4.8x				4.9x
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		4.8x				4.8x

(a) Net income excludes undistributed income for equity investees.

(b) Represents interest portion of rents estimated at 33 1/3%.

(c) Represents interest, amortization of debt discount and expense on all indebtedness and amortization of interest capitalized, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income) and interest capitalized.

(d) Represents rents (as defined above), interest, amortization of debt discount and expense on all indebtedness, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income).

EX-31.A

CERTIFICATION

I, David L. Goodin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  May 7, 2014

/s/ David L. Goodin

David L. Goodin

President and Chief Executive Officer

EX-31.B

CERTIFICATION

I, Doran N. Schwartz, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  May 7, 2014

/s/ Doran N. Schwartz

Doran N. Schwartz

Vice President and Chief Financial Officer

EX-32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Each of the undersigned, David L. Goodin, the President and Chief Executive Officer, and Doran N. Schwartz, the Vice President and Chief Financial Officer of MDU Resources Group, Inc. (the "Company"), DOES HEREBY CERTIFY that:

1.  The Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (the "Report"), fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

2.  Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHERE OF, each of the undersigned has executed this statement this 7th day of May, 2014.

/s/ David L. Goodin

David L. Goodin

President and Chief Executive Officer

/s/ Doran N. Schwartz

Doran N. Schwartz

Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to MDU Resources Group, Inc. and will be retained by MDU Resources Group, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95

MDU RESOURCES GROUP, INC.

MINE SAFETY INFORMATION

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Act), as amended by the Mine Improvement and New Emergency Response Act of 2006 (Mine Safety Act). The Dodd-Frank Act requires reporting of the following types of citations or orders:

1. Citations issued under Section 104 of the Mine Safety Act for violations that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard.

2. Orders issued under Section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under Section 104 have not been totally abated within the time period allowed by the citation or subsequent extensions.

3. Citations or orders issued under Section 104(d) of the Mine Safety Act. Citations or orders are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standards. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence.

4. Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.

5. Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.

6. Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards.

During the three months ended March 31, 2014, none of the Company's operating subsidiaries received citations or orders under the following sections of the Mine Safety Act: 104(b), 104(d), 110(b)(2), 107(a) or 104(e). In addition, the Company did not have any mining-related fatalities during this period.

1

MSHA Identification Number	Section 104 S&S Citations (#)	Total Dollar Value of MSHA Assessments Proposed ($)		Legal Actions Pending as of Last Day of Period (#)	Legal Actions Initiated During Period (#)	Legal Actions Resolved During Period (#)
04-00081	—	$	—	4	—	—
04-01698	—	100		1	1	—
04-05459	—	—		2	1	—
21-00462	—	—		—	—	1
21-02702	—	200		—	—	—
21-03096	—	400		—	—	—
21-03248	—	176		1	1	—
24-02022	—	—		—	—	1
32-00778	—	576		—	—	—
32-00950	—	—		2	—	—
35-00495	—	300		—	—	—
35-03449	—	200		—	—	—
35-03478	—	100		—	—	—
35-03527	—	2,149		—	—	—
35-03642	1	—		—	—	—
35-03667	2	392		—	—	—
48-01383	—	823		—	—	—
48-01670	—	100		—	—	—
51-00036	—	4,347		5	—	—
51-00171	—	100		—	—	—
	3	$	9,963	15	3	2

Legal actions pending before the Federal Mine Safety and Health Review Commission (the Commission) may involve, among other questions, challenges by operators to citations, orders and penalties they have received from the Federal Mine Safety and Health Administration (MSHA) or complaints of discrimination by miners under section 105 of the Mine Act. The following is a brief description of the types of legal actions that may be brought before the Commission.

• Contests of Citations and Orders - A contest proceeding may be filed with the Commission by operators, miners or miners' representatives to challenge the issuance of a citation or order issued by MSHA.

• Contests of Proposed Penalties (Petitions for Assessment of Penalties) - A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the alleged violation contained in a citation or order.

• Complaints for Compensation - A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders.

• Complaints of Discharge, Discrimination or Interference - A discrimination proceeding is a case that involves a miner's allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint.

• Applications for Temporary Relief - Applications for temporary relief from any modification or termination of any order or from any order issued under section 104 of the Mine Act.

• Appeals of Judges' Decisions or Orders to the Commission - A filing with the Commission for discretionary review of a judge's decision or order by a person who has been adversely affected or aggrieved by such decision or order.

The following table reflects the types of legal actions pending before the Commission as of March 31, 2014:

2

MSHA Identification Number	Contests of Citations and Orders	Contests of Proposed Penalties	Complaints for Compensation	Complaints of Discharge, Discrimination or Interference	Applications for Temporary Relief	Appeals of Judges' Decisions or Orders to the Commission
04-00081	—	—	—	—	—	4
04-01698	1	—	—	—	—	—
04-05459	2	—	—	—	—	—
21-03248	1	—	—	—	—	—
32-00950	2	—	—	—	—	—
51-00036	—	5	—	—	—	—
	6	5	—	—	—	4

3

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Accounts receivable and allowance for doubtful accounts (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Receivables [Abstract]
Receivables past due 90 days or more	$ 22.6	$ 36.4	$ 39.6
Allowance for doubtful accounts receivable	$ 10.9	$ 10.1	$ 10.8

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Fair value measurements (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Concentration risks, percentage [Abstract]
Percentage investment in common stock of mid-cap companies	29.00%		29.00%		29.00%
Percentage investment in common stock of small-cap companies	27.00%		28.00%		28.00%
Percentage investment in common stock of large-cap companies	28.00%		28.00%		28.00%
Percentage in fixed-income and other investments	16.00%		15.00%		15.00%
Fair value, measurements, recurring [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	$ 93,933		$ 93,657		$ 101,013
Liabilities, fair value disclosure	12,186		7,483		12,445
Fair value, measurements, recurring [Member] | Commodity derivative instruments [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure	12,186		7,483		7,987
Fair value, measurements, recurring [Member] | Interest rate swap [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure					4,458
Fair value, measurements, recurring [Member] | Money market funds [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	20,267		19,227		31,281
Fair value, measurements, recurring [Member] | Insurance contract [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	63,269	[1]	62,370	[2]	53,334	[2]
Fair value, measurements, recurring [Member] | Mortgage backed securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	7,989		8,193		8,879
Fair value, measurements, recurring [Member] | US Treasury securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	2,078		1,917		1,340
Fair value, measurements, recurring [Member] | Commodity derivative instruments , assets [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	330		1,950		6,179
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Liabilities, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Commodity derivative instruments [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Interest rate swap [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure					0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Money market funds [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Insurance contract [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0	[1]	0	[2]	0	[2]
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Mortgage backed securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | US Treasury securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 1 [Member] | Commodity derivative instruments , assets [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	93,933		93,657		101,013
Liabilities, fair value disclosure	12,186		7,483		12,445
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Commodity derivative instruments [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure	12,186		7,483		7,987
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Interest rate swap [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure					4,458
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Money market funds [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	20,267		19,227		31,281
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Insurance contract [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	63,269	[1]	62,370	[2]	53,334	[2]
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Mortgage backed securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	7,989		8,193		8,879
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | US Treasury securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	2,078		1,917		1,340
Fair value, measurements, recurring [Member] | Fair value, inputs, level 2 [Member] | Commodity derivative instruments , assets [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	330		1,950		6,179
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Liabilities, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Commodity derivative instruments [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Interest rate swap [Member]
Fair value measurements [Line Items]
Liabilities, fair value disclosure					0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Money market funds [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Insurance contract [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0	[1]	0	[2]	0	[2]
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Mortgage backed securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | US Treasury securities [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	0		0		0
Fair value, measurements, recurring [Member] | Fair value, inputs, level 3 [Member] | Commodity derivative instruments , assets [Member]
Fair value measurements [Line Items]
Assets, fair value disclosure	$ 0		$ 0		$ 0

[1] The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 27 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 16 percent in fixed-income investments.

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

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Other intangible assets (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net (excluding goodwill)	$ 12,296,000	$ 16,318,000	$ 13,099,000
Amortization of intangible assets	800,000	800,000
Estimated amortization expense for amortizable intangible assets [Abstract]
2014	3,200,000
2015	2,500,000
2016	2,200,000
2017	2,000,000
2018	1,000,000
Thereafter	2,200,000
Customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, gross	21,310,000	21,310,000	21,310,000
Intangible assets, accumulated amortization	(14,230,000)	(12,211,000)	(13,726,000)
Intangible assets, net (excluding goodwill)	7,080,000	9,099,000	7,584,000
Noncompete agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, gross	5,580,000	7,236,000	6,186,000
Intangible assets, accumulated amortization	(4,335,000)	(5,439,000)	(4,840,000)
Intangible assets, net (excluding goodwill)	1,245,000	1,797,000	1,346,000
Other intangible assets [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, gross	10,920,000	10,979,000	10,995,000
Intangible assets, accumulated amortization	(6,949,000)	(5,557,000)	(6,826,000)
Intangible assets, net (excluding goodwill)	$ 3,971,000	$ 5,422,000	$ 4,169,000

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Fair value measurements (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Carrying amount [Member]
Fair value, balance sheet grouping [Line Items]
Long-term debt	$ 2,105,832	$ 1,854,563	$ 1,789,663
Fair value [Member]
Fair value, balance sheet grouping [Line Items]
Long-term debt	$ 2,186,839	$ 1,912,590	$ 1,925,859

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Equity method investments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Aug. 31, 2013 ECTE [Member]	Aug. 31, 2012 ECTE [Member]	Nov. 30, 2011 ECTE [Member]	Nov. 30, 2010 ECTE [Member]	Nov. 30, 2010 ENTE [Member]	Nov. 30, 2010 ERTE [Member]
Schedule of Equity Method Investments [Line Items]
Percentage ownership interest in equity method investment sold					59.96%	100.00%	100.00%
Number of years over which remaining ownership interest in equity method investment will be sold					4 years
Portion of remaining interest sold		25.00%	25.00%	25.00%
Total assets of equity method investments	$ 142.9
Total long-term debt of equity method investments	63.9
Investment in equity method investments	5.7
Undistributed earnings of equity method investments	$ 2.2

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Derivative instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments, gain (losses)

The gains and losses on derivative instruments were as follows:

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax	$	—		$	(6,154	)
Amount of (gain) loss reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	244			(2,843		)
Amount of loss recognized in operating revenues (ineffective portion), before tax	—			(1,422		)
Interest rate derivatives designated as cash flow hedges:
Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax	—			305
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	100			71
Amount of loss recognized in interest expense (ineffective portion), before tax	—			(159		)
Commodity derivatives not designated as hedging instruments:
Amount of loss recognized in operating revenues, before tax	(6,712		)	(4,410		)

Derivative instruments

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

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	1,623	$	—
		—		1,623		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	81		4,313		1,447
	Other assets - noncurrent	249		243		503
		330		4,556		1,950
Total asset derivatives		$	330	$	6,179	$	1,950

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	5,994	$	—
	Other liabilities - noncurrent	—		534		—
Interest rate derivatives	Other accrued liabilities	—		4,458		—
		—		10,986		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	12,186		1,385		7,483
	Other liabilities - noncurrent	—		74		—
		12,186		1,459		7,483
Total liability derivatives		$	12,186	$	12,445	$	7,483

Offsetting assets and liabilities master netting

The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:

March 31, 2014	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	330	$	(330	)	$	—
Total assets	$	330	$	(330	)	$	—
Liabilities:
Commodity derivatives	$	12,186	$	(330	)	$	11,856
Total liabilities	$	12,186	$	(330	)	$	11,856

March 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	6,179	$	(3,578	)	$	2,601
Total assets	$	6,179	$	(3,578	)	$	2,601
Liabilities:
Commodity derivatives	$	7,987	$	(3,578	)	$	4,409
Interest rate derivatives	4,458		—			4,458
Total liabilities	$	12,445	$	(3,578	)	$	8,867

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

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Equity (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Balance
Total stockholders' equity	$ 2,823,164
Noncontrolling interest	32,738
Total equity	2,855,902	2,648,248
Net loss attributable to noncontrolling interest	(523)	0
Net income (loss)	56,139	56,515
Other comprehensive income	667	(7,894)
Dividends declared on preferred stocks	(171)	(171)
Dividends declared on common stock	(33,809)	(32,573)
Stock-based compensation	1,336	1,176
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	(5,564)
Net tax benefit on stock-based compensation	4,729	(1,419)
Issuance of common stock	54,574
Contribution from noncontrolling interest	16,001	11,100
Total stockholders' equity	2,901,588	2,663,882
Noncontrolling interest	48,216	11,100
Total equity	2,949,804	2,674,982
Total stockholders’ equity [Member]
Balance
Total stockholders' equity	2,823,164	2,648,248
Net income (loss) attributable to parent	56,662	56,515
Other comprehensive income	667	(7,894)
Dividends declared on preferred stocks	(171)	(171)
Dividends declared on common stock	(33,809)	(32,573)
Stock-based compensation	1,336	1,176
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	(5,564)
Net tax benefit on stock-based compensation	4,729	(1,419)
Issuance of common stock	54,574
Contribution from noncontrolling interest	0	0
Total stockholders' equity	2,901,588	2,663,882
Noncontrolling interest [Member]
Balance
Noncontrolling interest	32,738	0
Net loss attributable to noncontrolling interest		0
Other comprehensive income	0	0
Dividends declared on preferred stocks	0	0
Dividends declared on common stock	0	0
Stock-based compensation	0	0
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	0
Net tax benefit on stock-based compensation	0	0
Issuance of common stock	0
Contribution from noncontrolling interest	16,001	11,100
Noncontrolling interest	$ 48,216	$ 11,100

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Regulatory matters and revenues subject to refund

3 Months Ended

Mar. 31, 2014

Regulated Operations [Abstract]

Regulatory matters and revenues subject to refund

Regulatory matters and revenues subject to refund

On April 8, 2014, Montana-Dakota submitted a request to the NDPSC to update the environmental cost recovery rider to reflect actual costs incurred through February 2014 and projected costs through June 2015 related to the recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. If approved, the rates would be effective with service rendered on and after July 1, 2014.

On September 18, 2013, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of $6.8 million annually or approximately 6.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. An interim increase of $4.3 million annually or approximately 4.0 percent went into effect for service rendered on or after November 17, 2013. On December 30, 2013, the NDPSC approved a settlement agreement for an increase in the same amount as the interim increase. A hearing on the rate design portion of the case was held February 5, 2014. The NDPSC voted to approve an order approving the allocation of the revenue increase to each rate class and the rate design on April 9, 2014. Final rates were implemented May 1, 2014.

On February 27, 2014, Montana-Dakota filed an application with the NDPSC for approval of an electric generation resource recovery rider for recovery of Montana-Dakota's investment in the 88-megawatt simple-cycle natural gas turbine and associated facilities currently under construction near Mandan, ND. Montana-Dakota requested recovery of $7.4 million annually or approximately 4.6 percent above current rates. Advance determination of prudence and a certificate of public convenience and necessity were received from the NDPSC on April 11, 2012. On March 12, 2014, the NDPSC suspended the filing pending further review. The NDPSC has scheduled a hearing for this matter on May 28, 2014.

On October 31, 2013, WBI Energy Transmission filed a general natural gas rate change application with the FERC for an increase of $28.9 million annually to cover increased investments of $312 million, increased operating costs, and the effect of lower storage and off system volumes. On April 30, 2014, WBI Energy Transmission reached a settlement in principle with FERC Trial Staff and all active parties to resolve the rate case. WBI Energy Transmission intends to file the settlement rates to take effect on an interim basis, effective May 1, 2014, pending final approval of the settlement. The settlement, if approved, will result in final rates which are lower than the rates which were originally requested in the rate case application.

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Gains and losses on derivative instruments (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	$ 0	$ (5,849)
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	344	(2,772)
Commodity derivatives designated as cash flow hedges [Member]
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	(6,154)
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	244	(2,843)
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	0	(1,422)
Interest rate derivatives designated as cash flow hedges [Member]
Derivative instruments [Line Items]
Amount of gain (loss) recognized in accumulated other comprehensive loss (effective portion), net of tax	0	305
Amount of (gain) loss reclassified from accumulated other comprehensive loss (effective portion), net of tax	100	71
Amount of gain (loss) recognized in income statement (ineffective portion), before tax	0	(159)
Commodity derivatives not designated as hedging instruments:
Derivative instruments [Line Items]
Amount of gain (loss) recognized in operating revenues, before tax	$ (6,712)	$ (4,410)

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Cash flow information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Supplemental Cash Flow Information [Abstract]
Interest, net of amount capitalized	$ 20,850	$ 21,857
Income taxes paid (refunded), net	9,435	(7,246)
Property, plant and equipment additions in accounts payable	$ 65,736	$ 92,236

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Employee benefit plans (Tables)

3 Months Ended

Mar. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]

Schedule of net benefit costs

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 March 31,	2014			2013			2014			2013
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	33		$	40		$	379		$	504
Interest cost	4,440			4,018			858			940
Expected return on assets	(5,125		)	(5,083		)	(1,067		)	(1,107		)
Amortization of prior service cost (credit)	18			18			(348		)	(364		)
Amortization of net actuarial loss	1,313			1,864			318			671
Net periodic benefit cost, including amount capitalized	679			857			140			644
Less amount capitalized	95			110			29			29
Net periodic benefit cost	$	584		$	747		$	111		$	615

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Subject to master netting agreements (Details 4) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	$ 330	$ 1,950	$ 6,179
Derivative liability fair value gross liability	12,186	7,483	12,445
Commodity derivatives [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	330	1,950	6,179
Gross amount not offset	(330)	(1,950)	(3,578)
Derivative asset, fair value, net	0	0	2,601
Total assets [Member]
Derivative instruments [Line Items]
Derivative asset, fair value, gross asset	330	1,950	6,179
Gross amount not offset	(330)	(1,950)	(3,578)
Derivative asset, fair value, net	0	0	2,601
Commodity derivatives - liabilities [Member]
Derivative instruments [Line Items]
Derivative liability fair value gross liability	12,186	7,483	7,987
Gross amount not offset	(330)	(1,950)	(3,578)
Derivative liability, fair value, net	11,856	5,533	4,409
Interest rate derivatives - liabilities [Member]
Derivative instruments [Line Items]
Derivative liability fair value gross liability			4,458
Gross amount not offset			0
Derivative liability, fair value, net			4,458
Total liabilities [Member]
Derivative instruments [Line Items]
Derivative liability fair value gross liability	12,186	7,483	12,445
Gross amount not offset	(330)	(1,950)	(3,578)
Derivative liability, fair value, net	$ 11,856	$ 5,533	$ 8,867

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Litigation (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Aug. 31, 2011 Litigation related to construction materials [Member]	Oct. 31, 2010 Natural gas gathering operations [Member]	Jan. 13, 2012 Guarantee obligation under construction contract [Member]	Dec. 31, 2009 Guarantee obligation under construction contract [Member]
Loss Contingencies [Line Items]
Potential liabilities related to litigation and environmental matters	$ 31,400,000	$ 29,500,000	$ 33,300,000
Amount of compensatory damages in LPP's notice of demand							149,700,000
Arbitration award					26,600,000	22,000,000
Loss contingency, estimate of possible loss				3,700,000
Additional amount per day of potential penalties				$ 5,000

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Goodwill rollforward (Details) (USD $)	3 Months Ended				12 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Goodwill [Roll Forward]
Balance as of beginning of period	$ 636,039,000	[1]	$ 636,039,000	[1]	$ 636,039,000	[1]
Goodwill acquired during the year	0		0		0
Balance as of end of period	636,039,000	[1]	636,039,000	[1]	636,039,000	[1]
Natural gas distribution [Member]
Goodwill [Roll Forward]
Balance as of beginning of period	345,736,000		345,736,000		345,736,000
Goodwill acquired during the year	0		0		0
Balance as of end of period	345,736,000		345,736,000		345,736,000
Pipeline and energy services [Member]
Goodwill [Line Items]
Goodwill, impaired, accumulated impairment loss	12,300,000		12,300,000		12,300,000
Goodwill [Roll Forward]
Balance as of beginning of period	9,737,000	[1]	9,737,000	[1]	9,737,000	[1]
Goodwill acquired during the year	0		0		0
Balance as of end of period	9,737,000	[1]	9,737,000	[1]	9,737,000	[1]
Construction materials and contracting [Member]
Goodwill [Roll Forward]
Balance as of beginning of period	176,290,000		176,290,000		176,290,000
Goodwill acquired during the year	0		0		0
Balance as of end of period	176,290,000		176,290,000		176,290,000
Construction services [Member]
Goodwill [Roll Forward]
Balance as of beginning of period	104,276,000		104,276,000		104,276,000
Goodwill acquired during the year	0		0		0
Balance as of end of period	$ 104,276,000		$ 104,276,000		$ 104,276,000

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

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Seasonality of operations

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Seasonality of operations

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.

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Enviromental matters (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2014
Portland Harbor Site [Member]
Site Contingency [Line Items]
Environmental matters investigative costs	$ 70,000,000
Eugene,OR Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Site contingency, low estimate, loss exposure	500,000
Site contingency, high estimate, loss exposure	11,000,000
Estimated proportional share of cleanup liability	50.00%
Accrual for environmental loss contingencies	1,700,000
Bremerton, WA Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Site contingency, low estimate, loss exposure	340,000
Site contingency, high estimate, loss exposure	6,400,000
Accrual for environmental loss contingencies	12,800,000
Bellingham, WA Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Site contingency, loss exposure not accrued, best estimate	$ 8,000,000

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Comprehensive income (loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	$ (38,205)	$ (48,721)
Other comprehensive income (loss) before reclassifications	10	(5,805)
Amounts reclassified from accumulated other comprehensive loss	657	(2,089)
Net current-period other comprehensive income (loss)	667	(7,894)
Balance	(37,538)	(56,615)
Net unrealized gain (loss) on derivative instruments qualifying as hedges
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(3,765)	6,018
Other comprehensive income (loss) before reclassifications	0	(5,849)
Amounts reclassified from accumulated other comprehensive loss	344	(2,772)
Net current-period other comprehensive income (loss)	344	(8,621)
Balance	(3,421)	(2,603)
Postretirement liability adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(33,807)	(54,347)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive loss	275	648
Net current-period other comprehensive income (loss)	275	648
Balance	(33,532)	(53,699)
Foreign currency translation adjustment
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	(667)	(511)
Other comprehensive income (loss) before reclassifications	46	88
Amounts reclassified from accumulated other comprehensive loss	0	0
Net current-period other comprehensive income (loss)	46	88
Balance	(621)	(423)
Net unrealized gain (loss) on available-for-sale investments
Accumulated other comprehensive income (loss) [Roll Forward]
Balance	34	119
Other comprehensive income (loss) before reclassifications	(36)	(44)
Amounts reclassified from accumulated other comprehensive loss	38	35
Net current-period other comprehensive income (loss)	2	(9)
Balance	$ 36	$ 110

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Earnings per common share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Weighted average common shares outstanding

A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings per share calculations was as follows:

	Three Months Ended
	March 31,
	2014	2013
	(In thousands)
Weighted average common shares outstanding - basic	189,820	188,831
Effect of dilutive performance share awards	612	391
Weighted average common shares outstanding - diluted	190,432	189,222
Shares excluded from the calculation of diluted earnings per share	—	—

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Inventories and natural gas in storage (Tables)

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventories

Inventories consisted of:

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
Aggregates held for resale	$	104,106	$	98,120	$	101,568
Asphalt oil	66,292		94,332		38,099
Materials and supplies	68,809		75,868		69,808
Merchandise for resale	22,463		24,342		21,720
Natural gas in storage (current)	6,129		12,811		16,417
Other	33,533		29,399		34,779
Total	$	301,332	$	334,872	$	282,391

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Long-term debt (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Debt Instrument, Term	2 years
Term loan agreement	$ 125.0
Long-term commercial paper	$ 283.5	$ 153.9

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Reclassification out of accumulated other comprehensive income (loss) (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Revenues	$ 1,042,853	$ 931,604
Other income	2,132	1,242
Interest expense	(20,971)	(20,874)
Income before income taxes	84,116	84,588
Income taxes	27,932	27,996
Net income (loss)	56,139	56,515
Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Income before income taxes	(548)	4,398
Income taxes	204	(1,626)
Net income (loss)	(344)	2,772
Amortization of postretirement liability losses included in net periodic benefit cost
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Net periodic benefit cost	(443)	(967)
Income taxes	168	319
Net income (loss)	(275)	(648)
Reclassification adjustment for loss on available-for-sale investments included in net income
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Other income	(58)	(54)
Income taxes	20	19
Net income (loss)	(38)	(35)
Total reclassifications
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Net income (loss)	(657)	2,089
Commodity derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Revenues	(388)	4,513
Interest rate derivative instruments [Member] | Reclassification adjustment for gain (loss) on derivative instruments included in net income
Reclassification adjustment out of accumulated other comprehensive income [Line Items]
Interest expense	$ (160)	$ (115)

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Cash flow information (Tables)

3 Months Ended

Mar. 31, 2014

Supplemental Cash Flow Information [Abstract]

Supplemental cash flow information

Cash expenditures for interest and income taxes were as follows:

	Three Months Ended
	March 31,
	2014		2013
	(In thousands)
Interest, net of amount capitalized	$	20,850	$	21,857
Income taxes paid (refunded), net	$	9,435	$	(7,246	)

Noncash investing transactions were as follows:

	March 31,
	2014		2013
	(In thousands)
Property, plant and equipment additions in accounts payable	$	65,736	$	92,236

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Comprehensive income (loss) (Tables)

3 Months Ended

Mar. 31, 2014

Comprehensive income (loss) [Abstract]

Comprehensive income (loss)

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2014, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)
Other comprehensive income (loss) before reclassifications	—			—			46			(36		)	10
Amounts reclassified from accumulated other comprehensive loss	344			275			—			38			657
Net current-period other comprehensive income	344			275			46			2			667
Balance at March 31, 2014	$	(3,421	)	$	(33,532	)	$	(621	)	$	36		$	(37,538	)

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2013, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
Other comprehensive income (loss) before reclassifications	(5,849		)	—			88			(44		)	(5,805		)
Amounts reclassified from accumulated other comprehensive loss	(2,772		)	648			—			35			(2,089		)
Net current-period other comprehensive income (loss)	(8,621		)	648			88			(9		)	(7,894		)
Balance at March 31, 2013	$	(2,603	)	$	(53,699	)	$	(423	)	$	110		$	(56,615	)

Reclassification out of accumulated other comprehensive income

Reclassifications out of accumulated other comprehensive loss were as follows:

	Three Months Ended						Location on Consolidated Statements of Income
	March 31, 2014			March 31, 2013
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	(388	)	$	4,513		Operating revenues
Interest rate derivative instruments	(160		)	(115		)	Interest expense
	(548		)	4,398
	204			(1,626		)	Income taxes
	(344		)	2,772
Amortization of postretirement liability losses included in net periodic benefit cost	(443		)	(967		)	(a)
	168			319			Income taxes
	(275		)	(648		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(58		)	(54		)	Other income
	20			19			Income taxes
	(38		)	(35		)
Total reclassifications	$	(657	)	$	2,089

(a) Included in net periodic benefit cost (credit). For more information, see Note 17.

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Basis of presentation

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of presentation

Basis of presentation

The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2013 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2013 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 March 31, 2014, up to the date of issuance of these consolidated interim financial statements.

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Goodwill and other intangible assets (Tables)

3 Months Ended

Mar. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Changes in the carrying amount of goodwill

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

Three Months Ended March 31, 2014	Balance as of January 1, 2014*		Goodwill Acquired During the Year		Balance as of March 31, 2014*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Three Months Ended March 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of March 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Year Ended December 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of December 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Other amortizable intangible assets

Other amortizable intangible assets were as follows:

	March 31, 2014			March 31, 2013			December 31, 2013
	(In thousands)
Customer relationships	$	21,310		$	21,310		$	21,310
Accumulated amortization	(14,230		)	(12,211		)	(13,726		)
	7,080			9,099			7,584
Noncompete agreements	5,580			7,236			6,186
Accumulated amortization	(4,335		)	(5,439		)	(4,840		)
	1,245			1,797			1,346
Other	10,920			10,979			10,995
Accumulated amortization	(6,949		)	(5,557		)	(6,826		)
	3,971			5,422			4,169
Total	$	12,296		$	16,318		$	13,099

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Inventories and natural gas in storage (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Inventory Disclosure [Abstract]
Aggregates held for resale	$ 104,106,000	$ 101,568,000	$ 98,120,000
Asphalt oil	66,292,000	38,099,000	94,332,000
Materials and supplies	68,809,000	69,808,000	75,868,000
Merchandise for resale	22,463,000	21,720,000	24,342,000
Natural gas in storage (current)	6,129,000	16,417,000	12,811,000
Other	33,533,000	34,779,000	29,399,000
Total	301,332,000	282,391,000	334,872,000
Natural gas in storage noncurrent	$ 47,400,000	$ 48,300,000	$ 49,600,000

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Available-for-sale securities (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Available-for-sale securities [Line Items]
Investments used to satisfy obligations under nonqualified benefit plans	$ 63,300,000	$ 53,300,000	$ 62,400,000
Net unrealized gain (loss) of investments used to satify obligations under nonqualified benefit plans	900,000	4,400,000
Available-for-sale securities [Abstract]
Cost	10,012,000	10,050,000	10,057,000
Gross unrealized gains	72,000	172,000	84,000
Gross unrealized losses	(17,000)	(3,000)	(31,000)
Fair value	10,067,000	10,219,000	10,110,000
Mortgage backed securities [Member]
Available-for-sale securities [Abstract]
Cost	7,943,000	8,749,000	8,151,000
Gross unrealized gains	63,000	133,000	69,000
Gross unrealized losses	(17,000)	(3,000)	(27,000)
Fair value	7,989,000	8,879,000	8,193,000
US Treasury securities [Member]
Available-for-sale securities [Abstract]
Cost	2,069,000	1,301,000	1,906,000
Gross unrealized gains	9,000	39,000	15,000
Gross unrealized losses	0	0	(4,000)
Fair value	$ 2,078,000	$ 1,340,000	$ 1,917,000

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating revenues:
Electric, natural gas distribution and pipeline and energy services	$ 491,541	$ 424,124
Exploration and production, construction materials and contracting, construction services and other	551,312	507,480
Total operating revenues	1,042,853	931,604
Operating expenses:
Fuel and purchased power	26,544	21,608
Purchased natural gas sold	244,892	199,187
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services	67,284	66,101
Exploration and production, construction materials and contracting, construction services and other	445,951	394,019
Depreciation, depletion and amortization	99,557	93,561
Taxes, other than income	55,721	52,597
Total operating expenses	939,949	827,073
Operating income	102,904	104,531
Earnings (loss) from equity method investments	51	(311)
Other income	2,132	1,242
Interest expense	20,971	20,874
Income before income taxes	84,116	84,588
Income taxes	27,932	27,996
Income from continuing operations	56,184	56,592
Loss from discontinued operations, net of tax (Note 9)	(45)	(77)
Net income (loss)	56,139	56,515
Net loss attributable to noncontrolling interest	(523)	0
Dividends declared on preferred stocks	171	171
Earnings on common stock	$ 56,491	$ 56,344
Earnings per common share - basic:
Earnings before discontinued operations	$ 0.30	$ 0.30
Discontinued operations, net of tax	$ 0.00	$ 0.00
Earnings per common share - basic	$ 0.30	$ 0.30
Earnings per common share - diluted:
Earnings before discontinued operations	$ 0.30	$ 0.30
Discontinued operations, net of tax	$ 0.00	$ 0.00
Earnings per common share - diluted	$ 0.30	$ 0.30
Dividends declared per common share	$ 0.1775	$ 0.1725
Weighted average common shares outstanding - basic	189,820	188,831
Weighted average common shares outstanding - diluted	190,432	189,222

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Acquisition (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Mar. 06, 2014
Business Combinations [Abstract]
Business acquisition, cost of acquired entity, purchase price	$ 206.3

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Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Stockholders' equity:
Common stock, shares authorized	500,000,000	500,000,000	500,000,000
Common stock, par value	$ 1.00	$ 1.00	$ 1.00
Common stock, shares issued	191,838,720	189,868,780	189,369,450
Treasury shares	538,921	538,921	538,921

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Employee benefit plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension benefits [Member]
Defined benefit plan disclosure, net periodic benefit cost [Line Items]
Service cost	$ 33	$ 40
Interest cost	4,440	4,018
Expected return on assets	(5,125)	(5,083)
Amortization of prior service cost (credit)	18	18
Amortization of net actuarial loss	1,313	1,864
Net periodic benefit cost, including amount capitalized	679	857
Less amount capitalized	95	110
Net periodic benefit cost	584	747
Other postretirement benefits [Member]
Defined benefit plan disclosure, net periodic benefit cost [Line Items]
Service cost	379	504
Interest cost	858	940
Expected return on assets	(1,067)	(1,107)
Amortization of prior service cost (credit)	(348)	(364)
Amortization of net actuarial loss	318	671
Net periodic benefit cost, including amount capitalized	140	644
Less amount capitalized	29	29
Net periodic benefit cost	111	615
Supplemental employee retirement plans [Member]
Defined benefit plan disclosure, net periodic benefit cost [Line Items]
Net periodic benefit cost	$ 1,700	$ 1,900

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Equity (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Summary of changes in equity

A summary of the changes in equity was as follows:

Three Months Ended March 31, 2014	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2013	$	2,823,164		$	32,738		$	2,855,902
Net income (loss)	56,662			(523		)	56,139
Other comprehensive income	667			—			667
Dividends declared on preferred stocks	(171		)	—			(171		)
Dividends declared on common stock	(33,809		)	—			(33,809		)
Stock-based compensation	1,336			—			1,336
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	(5,564		)	—			(5,564		)
Net tax benefit on stock-based compensation	4,729			—			4,729
Issuance of common stock	54,574			—			54,574
Contribution from noncontrolling interest	—			16,001			16,001
Balance at March 31, 2014	$	2,901,588		$	48,216		$	2,949,804

Three Months Ended March 31, 2013	Total Stockholders' Equity			Noncontrolling Interest		Total Equity
	(In thousands)
Balance at December 31, 2012	$	2,648,248		$	—	$	2,648,248
Net income	56,515			—		56,515
Other comprehensive loss	(7,894		)	—		(7,894		)
Dividends declared on preferred stocks	(171		)	—		(171		)
Dividends declared on common stock	(32,573		)	—		(32,573		)
Stock-based compensation	1,176			—		1,176
Net tax deficit on stock-based compensation	(1,419		)	—		(1,419		)
Contribution from noncontrolling interest	—			11,100		11,100
Balance at March 31, 2013	$	2,663,882		$	11,100	$	2,674,982

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Subsquent event (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Mar. 31, 2014	Jan. 28, 2014 The Company [Member]	Apr. 02, 2014 Subsequent event [Member] Centennial Energy Holdings, Inc [Member]	Jul. 15, 2014 Subsequent event [Member] The Company [Member]	Apr. 15, 2014 Subsequent event [Member] The Company [Member]
Subsequent Event [Line Items]
Debt Instrument, Term	2 years		2 years
Term loan agreement	$ 125.0		$ 125.0
Note Purchase Agreement		150.0
Senior Notes Issued					50.0
Senior notes remained to be issued				$ 100.0
Senior notes weighted average interest rate				4.30%	5.20%

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Equity

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Equity

Equity

A summary of the changes in equity was as follows:

Three Months Ended March 31, 2014	Total Stockholders' Equity			Noncontrolling Interest			Total Equity
	(In thousands)
Balance at December 31, 2013	$	2,823,164		$	32,738		$	2,855,902
Net income (loss)	56,662			(523		)	56,139
Other comprehensive income	667			—			667
Dividends declared on preferred stocks	(171		)	—			(171		)
Dividends declared on common stock	(33,809		)	—			(33,809		)
Stock-based compensation	1,336			—			1,336
Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings	(5,564		)	—			(5,564		)
Net tax benefit on stock-based compensation	4,729			—			4,729
Issuance of common stock	54,574			—			54,574
Contribution from noncontrolling interest	—			16,001			16,001
Balance at March 31, 2014	$	2,901,588		$	48,216		$	2,949,804

Three Months Ended March 31, 2013	Total Stockholders' Equity			Noncontrolling Interest		Total Equity
	(In thousands)
Balance at December 31, 2012	$	2,648,248		$	—	$	2,648,248
Net income	56,515			—		56,515
Other comprehensive loss	(7,894		)	—		(7,894		)
Dividends declared on preferred stocks	(171		)	—		(171		)
Dividends declared on common stock	(32,573		)	—		(32,573		)
Stock-based compensation	1,176			—		1,176
Net tax deficit on stock-based compensation	(1,419		)	—		(1,419		)
Contribution from noncontrolling interest	—			11,100		11,100
Balance at March 31, 2013	$	2,663,882		$	11,100	$	2,674,982

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Business segment data (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Information on the Company's businesses

Information on the Company's businesses was as follows:

Three Months Ended March 31, 2014	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	73,647	$	—		$	11,033
Natural gas distribution	374,233		—			27,263
Pipeline and energy services	43,661		18,276			4,349
	491,541		18,276			42,645
Exploration and production	116,669		20,867			20,939
Construction materials and contracting	164,423		4,017			(23,574		)
Construction services	269,892		3,738			16,568
Other	328		1,724			264
	551,312		30,346			14,197
Intersegment eliminations	—		(48,622		)	(351		)
Total	$	1,042,853	$	—		$	56,491

Three Months Ended March 31, 2013	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	64,654	$	—		$	9,825
Natural gas distribution	331,754		—			32,518
Pipeline and energy services	27,716		18,718			2,330
	424,124		18,718			44,673
Exploration and production	115,363		9,812			20,284
Construction materials and contracting	161,977		4,294			(20,582		)
Construction services	229,806		1,574			11,664
Other	334		1,818			305
	507,480		17,498			11,671
Intersegment eliminations	—		(36,216		)	—
Total	$	931,604	$	—		$	56,344

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Employee benefit plans

3 Months Ended

Mar. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]

Pension and other postretirement benefit plans

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 March 31,	2014			2013			2014			2013
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	33		$	40		$	379		$	504
Interest cost	4,440			4,018			858			940
Expected return on assets	(5,125		)	(5,083		)	(1,067		)	(1,107		)
Amortization of prior service cost (credit)	18			18			(348		)	(364		)
Amortization of net actuarial loss	1,313			1,864			318			671
Net periodic benefit cost, including amount capitalized	679			857			140			644
Less amount capitalized	95			110			29			29
Net periodic benefit cost	$	584		$	747		$	111		$	615

In addition to the qualified plan defined pension benefits reflected in the table, the Company has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three months ended March 31, 2014 and 2013, was $1.7 million and $1.9 million, respectively.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating activities:
Net income (loss)	$ 56,139	$ 56,515
Loss from discontinued operations, net of tax	(45)	(77)
Income from continuing operations	56,184	56,592
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	99,557	93,561
Earnings (loss), net of distributions, from equity method investments	(51)	1,277
Deferred income taxes	35,965	44,663
Unrealized loss on commodity derivatives	6,712	5,832
Changes in current assets and liabilities, net of acquisitions:
Receivables	25,611	32,206
Inventories	(19,809)	(19,126)
Other current assets	(22,324)	(25,855)
Accounts payable	(11,525)	(35,091)
Other current liabilities	(28,355)	(7,338)
Other noncurrent changes	(4,936)	(10,150)
Net cash provided by continuing operations	137,029	136,571
Net cash provided by discontinued operations	8	303
Net cash provided by operating activities	137,037	136,874
Investing activities:
Capital expenditures	(179,646)	(188,475)
Acquisitions, net of cash acquired	(206,304)	0
Net proceeds from sale or disposition of property and other	5,179	18,176
Investments	458	(514)
Net cash used in continuing operations	(380,313)	(170,813)
Net cash provided by discontinued operations	0	0
Net cash used in investing activities	(380,313)	(170,813)
Financing activities:
Issuance of short-term borrowings	0	9,300
Repayment of short-term borrowings	(11,500)	0
Issuance of long-term debt	309,501	112,015
Repayment of long-term debt	(58,232)	(67,123)
Proceeds from issuance of common stock	54,843	0
Dividends paid	(33,737)	(171)
Excess tax benefit on stock-based compensation	4,833	0
Contribution from noncontrolling interest	16,000	5,000
Net cash provided by continuing operations	281,708	59,021
Net cash provided by discontinued operations	0	0
Net cash provided by financing activities	281,708	59,021
Effect of exchange rate changes on cash and cash equivalents	43	25
Increase in cash and cash equivalents	38,475	25,107
Cash and cash equivalents - beginning of year	45,225	49,042
Cash and cash equivalents - end of period	$ 83,700	$ 74,149

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Consolidated Statements of Comprehensive Income [Abstract]
Net income (loss)	$ 56,139	$ 56,515
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized loss on derivative instruments arising during the period, net of tax of $0 and $(3,168) for the three months ended in 2014 and 2013, respectively	0	(5,849)
Reclassification adjustment for (gain) loss on derivative instruments included in net income, net of tax of $204 and $(1,626) for the three months ended in 2014 and 2013, respectively	344	(2,772)
Net unrealized gain (loss) on derivative instruments qualifying as hedges	344	(8,621)
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $168 and $319 for the three months ended in 2014 and 2013, respectively	275	648
Foreign currency translation adjustment recognized during the period, net of tax of $28 and $37 for the three months ended in 2014 and 2013, respectively	46	88
Net unrealized gain (loss) on available-for-sale investments:
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(19) and $(24) for the three months ended in 2014 and 2013, respectively	(36)	(44)
Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $20 and $19 for the three months ended in 2014 and 2013, respectively	38	35
Net unrealized gain (loss) on available-for-sale investments	2	(9)
Other comprehensive income (loss)	667	(7,894)
Comprehensive income	56,806	48,621
Comprehensive loss attributable to noncontrolling interest	(523)	0
Comprehensive income attributable to common stockholders	$ 57,329	$ 48,621

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Equity method investments

3 Months Ended

Mar. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Equity method investments

Equity method investments

Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. At March 31, 2014, the Company had no significant equity method investments.

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

At March 31, 2013, the equity method investments had total assets of $142.9 million and long-term debt of $63.9 million. The Company's investment in its equity method investments was approximately $5.7 million, including undistributed earnings of $2.2 million, at March 31, 2013.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	MDU RESOURCES GROUP INC
Entity Central Index Key	0000067716
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		191,604,704
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014

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Goodwill and other intangible assets

3 Months Ended

Mar. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and other intangible assets

Goodwill and other intangible assets

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

Three Months Ended March 31, 2014	Balance as of January 1, 2014*		Goodwill Acquired During the Year		Balance as of March 31, 2014*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Three Months Ended March 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of March 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Year Ended December 31, 2013	Balance as of January 1, 2013*		Goodwill Acquired During the Year		Balance as of December 31, 2013*
	(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	104,276		—		104,276
Total	$	636,039	$	—	$	636,039

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

Other amortizable intangible assets were as follows:

	March 31, 2014			March 31, 2013			December 31, 2013
	(In thousands)
Customer relationships	$	21,310		$	21,310		$	21,310
Accumulated amortization	(14,230		)	(12,211		)	(13,726		)
	7,080			9,099			7,584
Noncompete agreements	5,580			7,236			6,186
Accumulated amortization	(4,335		)	(5,439		)	(4,840		)
	1,245			1,797			1,346
Other	10,920			10,979			10,995
Accumulated amortization	(6,949		)	(5,557		)	(6,826		)
	3,971			5,422			4,169
Total	$	12,296		$	16,318		$	13,099

Amortization expense for amortizable intangible assets for the three months ended March 31, 2014 and 2013, was $800,000 and $800,000, respectively. Estimated amortization expense for amortizable intangible assets is $3.2 million in 2014, $2.5 million in 2015, $2.2 million in 2016, $2.0 million in 2017, $1.0 million in 2018 and $2.2 million thereafter.

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Consolidated Statements of Comprehensive Income - Parenthetical (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net unrealized gain (loss) on derivative instruments arising during the period, tax	$ 0	$ (3,168)
Reclassification adjustment for (gain) loss on derivative instruments included in net income, tax	204	(1,626)
Amortization of postretirement liability losses included in net periodic benefit cost, tax	168	319
Foreign currency translation adjustments arising during the period, tax	28	37
Net unrealized gain (loss) on available-for-sale investments arising during the period, tax	(19)	(24)
Reclassification adjustment for (gain) loss on available-for-sale investments included in net income, tax	$ 20	$ 19

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Earnings per common share

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings per common share

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 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 calculations was as follows:

	Three Months Ended
	March 31,
	2014	2013
	(In thousands)
Weighted average common shares outstanding - basic	189,820	188,831
Effect of dilutive performance share awards	612	391
Weighted average common shares outstanding - diluted	190,432	189,222
Shares excluded from the calculation of diluted earnings per share	—	—

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Inventories and natural gas in storage

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventories and natural gas in storage

Inventories and natural gas in storage

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

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
Aggregates held for resale	$	104,106	$	98,120	$	101,568
Asphalt oil	66,292		94,332		38,099
Materials and supplies	68,809		75,868		69,808
Merchandise for resale	22,463		24,342		21,720
Natural gas in storage (current)	6,129		12,811		16,417
Other	33,533		29,399		34,779
Total	$	301,332	$	334,872	$	282,391

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, is included in other assets and was $47.4 million, $49.6 million, and $48.3 million at March 31, 2014 and 2013, and December 31, 2013, respectively.

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Business segment data

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Business segment data

Business segment data

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

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

The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment is constructing Dakota Prairie Refinery in conjunction with Calumet to refine crude oil and 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/Gulf States regions of the United States.

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, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' 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 2013 Annual Report. Information on the Company's businesses was as follows:

Three Months Ended March 31, 2014	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	73,647	$	—		$	11,033
Natural gas distribution	374,233		—			27,263
Pipeline and energy services	43,661		18,276			4,349
	491,541		18,276			42,645
Exploration and production	116,669		20,867			20,939
Construction materials and contracting	164,423		4,017			(23,574		)
Construction services	269,892		3,738			16,568
Other	328		1,724			264
	551,312		30,346			14,197
Intersegment eliminations	—		(48,622		)	(351		)
Total	$	1,042,853	$	—		$	56,491

Three Months Ended March 31, 2013	External Operating Revenues		Inter- segment Operating Revenues			Earnings on Common Stock
	(In thousands)
Electric	$	64,654	$	—		$	9,825
Natural gas distribution	331,754		—			32,518
Pipeline and energy services	27,716		18,718			2,330
	424,124		18,718			44,673
Exploration and production	115,363		9,812			20,284
Construction materials and contracting	161,977		4,294			(20,582		)
Construction services	229,806		1,574			11,664
Other	334		1,818			305
	507,480		17,498			11,671
Intersegment eliminations	—		(36,216		)	—
Total	$	931,604	$	—		$	56,344

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.

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Derivative instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

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 March 31, 2014, the Company had no outstanding foreign currency or interest rate hedges.

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

Fidelity

At March 31, 2014 and 2013, and December 31, 2013, Fidelity held oil swap and collar agreements with total forward notional volumes of 2.7 million, 2.8 million and 2.9 million Bbl, respectively, and natural gas swap agreements with total forward notional volumes of 14.7 million, 25.9 million and 18.3 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date. The Company expects to reclassify into earnings from accumulated other comprehensive income (loss) the remaining value related to de-designating commodity derivative instruments over the next 9 months.

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

Centennial

As of March 31, 2014 and December 31, 2013, Centennial had no outstanding interest rate swap agreements. At March 31, 2013, Centennial held interest rate swap agreements with total notional amounts of $40.0 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.

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. 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.

Fidelity and Centennial

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.

The gains and losses on derivative instruments were as follows:

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Commodity derivatives designated as cash flow hedges:
Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax	$	—		$	(6,154	)
Amount of (gain) loss reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax	244			(2,843		)
Amount of loss recognized in operating revenues (ineffective portion), before tax	—			(1,422		)
Interest rate derivatives designated as cash flow hedges:
Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax	—			305
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax	100			71
Amount of loss recognized in interest expense (ineffective portion), before tax	—			(159		)
Commodity derivatives not designated as hedging instruments:
Amount of loss recognized in operating revenues, before tax	(6,712		)	(4,410		)

Over the next 12 months net losses of approximately $449,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, 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 the 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 March 31, 2014 and 2013, and December 31, 2013, were $12.2 million, $12.4 million and $7.5 million, respectively. 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 March 31, 2014 and 2013, and December 31, 2013, were $12.2 million, $12.4 million and $7.5 million, respectively.

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

Asset Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	1,623	$	—
		—		1,623		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	81		4,313		1,447
	Other assets - noncurrent	249		243		503
		330		4,556		1,950
Total asset derivatives		$	330	$	6,179	$	1,950

Liability Derivatives	Location on Consolidated Balance Sheets	Fair Value at March 31, 2014		Fair Value at March 31, 2013		Fair Value at December 31, 2013
		(In thousands)
Designated as hedges:
Commodity derivatives	Commodity derivative instruments	$	—	$	5,994	$	—
	Other liabilities - noncurrent	—		534		—
Interest rate derivatives	Other accrued liabilities	—		4,458		—
		—		10,986		—
Not designated as hedges:
Commodity derivatives	Commodity derivative instruments	12,186		1,385		7,483
	Other liabilities - noncurrent	—		74		—
		12,186		1,459		7,483
Total liability derivatives		$	12,186	$	12,445	$	7,483

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

March 31, 2014	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	330	$	(330	)	$	—
Total assets	$	330	$	(330	)	$	—
Liabilities:
Commodity derivatives	$	12,186	$	(330	)	$	11,856
Total liabilities	$	12,186	$	(330	)	$	11,856

March 31, 2013	Gross Amounts Recognized on the Consolidated Balance Sheets		Gross Amounts Not Offset on the Consolidated Balance Sheets			Net
	(In thousands)
Assets:
Commodity derivatives	$	6,179	$	(3,578	)	$	2,601
Total assets	$	6,179	$	(3,578	)	$	2,601
Liabilities:
Commodity derivatives	$	7,987	$	(3,578	)	$	4,409
Interest rate derivatives	4,458		—			4,458
Total liabilities	$	12,445	$	(3,578	)	$	8,867

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

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Acquisition

3 Months Ended

Mar. 31, 2014

Business Combinations [Abstract]

Acquisition

Acquisition

On February 10, 2014, the Company entered into agreements to purchase working interests and leasehold positions in oil and natural gas production assets in the southern Powder River Basin of Wyoming. The effective date of the acquisition was October 1, 2013, and the closing occurred on March 6, 2014. The purchase price was $206.3 million, including purchase price adjustments.

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

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Regulatory matters and revenues subject to refund (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Feb. 27, 2014 NDPSC [Member]	Nov. 17, 2013 NDPSC [Member]	Sep. 18, 2013 NDPSC [Member]	Oct. 31, 2013 FERC [Member]
Regulatory matters and revenues subject to refund [Line Items]
Rate increase requested	$ 7.4		$ 6.8
Percent above current rates requested	4.60%		6.40%
Interim rate increase (decrease), amount		4.3
Interim rate increase, percent		4.00%
Rate change application annual increase, amount				28.9
Increased expenditures covered by change application				$ 312

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Cash flow information

3 Months Ended

Mar. 31, 2014

Supplemental Cash Flow Information [Abstract]

Cash flow information

Cash flow information

Cash expenditures for interest and income taxes were as follows:

	Three Months Ended
	March 31,
	2014		2013
	(In thousands)
Interest, net of amount capitalized	$	20,850	$	21,857
Income taxes paid (refunded), net	$	9,435	$	(7,246	)

Noncash investing transactions were as follows:

	March 31,
	2014		2013
	(In thousands)
Property, plant and equipment additions in accounts payable	$	65,736	$	92,236

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Comprehensive income (loss)

3 Months Ended

Mar. 31, 2014

Comprehensive income (loss) [Abstract]

Comprehensive income (loss)

Comprehensive income (loss)

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2014, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2013	$	(3,765	)	$	(33,807	)	$	(667	)	$	34		$	(38,205	)
Other comprehensive income (loss) before reclassifications	—			—			46			(36		)	10
Amounts reclassified from accumulated other comprehensive loss	344			275			—			38			657
Net current-period other comprehensive income	344			275			46			2			667
Balance at March 31, 2014	$	(3,421	)	$	(33,532	)	$	(621	)	$	36		$	(37,538	)

The after-tax changes in the components of accumulated other comprehensive loss at March 31, 2013, were as follows:

	Net Unrealized Gain (Loss) on Derivative  Instruments  Qualifying as Hedges			Postretirement  Liability Adjustment			Foreign Currency Translation Adjustment			Net Unrealized Gain (Loss) on Available-for-sale Investments			Total Accumulated  Other Comprehensive  Loss
	(In thousands)
Balance at December 31, 2012	$	6,018		$	(54,347	)	$	(511	)	$	119		$	(48,721	)
Other comprehensive income (loss) before reclassifications	(5,849		)	—			88			(44		)	(5,805		)
Amounts reclassified from accumulated other comprehensive loss	(2,772		)	648			—			35			(2,089		)
Net current-period other comprehensive income (loss)	(8,621		)	648			88			(9		)	(7,894		)
Balance at March 31, 2013	$	(2,603	)	$	(53,699	)	$	(423	)	$	110		$	(56,615	)

Reclassifications out of accumulated other comprehensive loss were as follows:

	Three Months Ended						Location on Consolidated Statements of Income
	March 31, 2014			March 31, 2013
	(In thousands)
Reclassification adjustment for gain (loss) on derivative instruments included in net income:
Commodity derivative instruments	$	(388	)	$	4,513		Operating revenues
Interest rate derivative instruments	(160		)	(115		)	Interest expense
	(548		)	4,398
	204			(1,626		)	Income taxes
	(344		)	2,772
Amortization of postretirement liability losses included in net periodic benefit cost	(443		)	(967		)	(a)
	168			319			Income taxes
	(275		)	(648		)
Reclassification adjustment for loss on available-for-sale investments included in net income	(58		)	(54		)	Other income
	20			19			Income taxes
	(38		)	(35		)
Total reclassifications	$	(657	)	$	2,089

(a) Included in net periodic benefit cost (credit). For more information, see Note 17.

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Discontinued operations

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Discontinued operations

Discontinued operations

In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources had 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, which are reflected as discontinued operations in the consolidated financial statements and accompanying notes, and has accrued liabilities related to this matter. Discontinued operations are included in the Other category. For more information, see Note 19.

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Commitment and contingencies variable interest entities (Details 4) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Dakota Prairie Refining, LLC [Member]
Variable Interest Entities [Line Items]
Percent of ownership	50.00%
Total project costs	$ 300,000,000
Portion of capital commitment	150,000,000
Partner portion of capital commitment	75,000,000
Excess capital commitments	300,000,000
Project cost estimate	350,000,000
Term loan for project debt financing	75,000,000
Dakota Prairie Refining, LLC [Member] | Cash and Cash Equivalents [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, assets	22,996,000	4,774,000	10,793,000
Dakota Prairie Refining, LLC [Member] | Other current assets [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, assets	1,135,000	26,000	0
Dakota Prairie Refining, LLC [Member] | Total current assets [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, assets	24,131,000	4,800,000	10,793,000
Dakota Prairie Refining, LLC [Member] | Net property, plant and equipment [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, assets	207,260,000	172,073,000	27,356,000
Dakota Prairie Refining, LLC [Member] | Total assets [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, assets	231,391,000	176,873,000	38,149,000
Dakota Prairie Refining, LLC [Member] | Long-term debt due within one year [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	3,000,000	3,000,000	0
Dakota Prairie Refining, LLC [Member] | Accounts payable [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	16,103,000	8,904,000	10,948,000
Dakota Prairie Refining, LLC [Member] | Taxes Payable [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	113,000	5,000	0
Dakota Prairie Refining, LLC [Member] | Accrued Compensation [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	164,000	26,000	0
Dakota Prairie Refining, LLC [Member] | Other accrued liabilities [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	580,000	461,000	0
Dakota Prairie Refining, LLC [Member] | Total current liabilities [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	19,960,000	12,396,000	10,948,000
Dakota Prairie Refining, LLC [Member] | Long-term debt [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	72,000,000	72,000,000	0
Dakota Prairie Refining, LLC [Member] | Total liabilities [Member]
Variable Interest Entities [Line Items]
Limited liability entity, consolidated, carrying amount, liabilities	91,960,000	84,396,000	10,948,000
Fuel contract [Member]
Variable Interest Entities [Line Items]
Variable interest entity, reporting entity involvement, maximum loss exposure, amount	$ 8,200,000

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Guarantees (Details 3) (USD $)	Mar. 31, 2014
Guarantor Obligations [Line Items]
Amount of hedging obligations guaranteed reflected on balance sheet	$ 7,700,000
Guarantor obligations, maximum exposure, undiscounted	48,700,000
Fixed maximum amounts guaranteed by year 2014	26,800,000
Fixed maximum amounts guaranteed by year 2015	2,100,000
Fixed maximum amounts guaranteed by year 2016	700,000
Fixed maximum amounts guaranteed by year 2017	600,000
Fixed maximum amounts guaranteed by year 2018	500,000
Fixed maximum amounts guaranteed by year 2019	500,000
Fixed maximum amounts guaranteed by year expires after certain number of days after written notice	13,500,000
No scheduled maturity date	4,000,000
Amount outstanding under guarantees that is reflected on balance sheet	200,000
Letters of credit	36,300,000
Letters of credit set to expire - 2014	7,000,000
Letters of credit set to expire - 2015	29,300,000
Outstanding letters of credit	0
Natural gas transportation and storage agreement fixed maximum amount of performance guarantee of a related party	4,000,000
Amount outstanding by a related party under the guarantee	700,000
Amount of surety bonds outstanding	$ 588,800,000

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Fair value measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Available-for-sale securities

Details of available-for-sale securities were as follows:

March 31, 2014	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	7,943	$	63	$	(17	)	$	7,989
U.S. Treasury securities	2,069		9		—			2,078
Total	$	10,012	$	72	$	(17	)	$	10,067

March 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,749	$	133	$	(3	)	$	8,879
U.S. Treasury securities	1,301		39		—			1,340
Total	$	10,050	$	172	$	(3	)	$	10,219

December 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

Assets and liabilities measured at fair value on a recurring basis

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

	Fair Value Measurements at March 31, 2014, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2014
	(In thousands)
Assets:
Money market funds	$	—	$	20,267	$	—	$	20,267
Insurance contract*	—		63,269		—		63,269
Available-for-sale securities:
Mortgage-backed securities	—		7,989		—		7,989
U.S. Treasury securities	—		2,078		—		2,078
Commodity derivative instruments	—		330		—		330
Total assets measured at fair value	$	—	$	93,933	$	—	$	93,933
Liabilities:
Commodity derivative instruments	$	—	$	12,186	$	—	$	12,186
Total liabilities measured at fair value	$	—	$	12,186	$	—	$	12,186

*  The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 27 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 16 percent in fixed-income investments.

	Fair Value Measurements at March 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	31,281	$	—	$	31,281
Insurance contract*	—		53,334		—		53,334
Available-for-sale securities:
Mortgage-backed securities	—		8,879		—		8,879
U.S. Treasury securities	—		1,340		—		1,340
Commodity derivative instruments	—		6,179		—		6,179
Total assets measured at fair value	$	—	$	101,013	$	—	$	101,013
Liabilities:
Commodity derivative instruments	$	—	$	7,987	$	—	$	7,987
Interest rate derivative instruments	—		4,458		—		4,458
Total liabilities measured at fair value	$	—	$	12,445	$	—	$	12,445

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

	Fair Value Measurements at December 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs  (Level 3)		Balance at December 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

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

Fair value of long term debt outstanding

The estimated fair value of the Company's Level 2 long-term debt was as follows:

	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at March 31, 2014	$	2,105,832	$	2,186,839
Long-term debt at March 31, 2013	$	1,789,663	$	1,925,859
Long-term debt at December 31, 2013	$	1,854,563	$	1,912,590

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Derivative instruments (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	$ 330	$ 1,950	$ 6,179
Derivative liability fair value gross liability	12,186	7,483	12,445
Designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative instruments in hedges, assets, at fair value	0	0	1,623
Derivative instruments in hedges, liabilities, at fair value	0	0	10,986
Designated as hedging instrument [Member] | Commodity contract [Member] | Commodity derivative instruments - current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative instruments in hedges, assets, at fair value	0	0	1,623
Designated as hedging instrument [Member] | Commodity contract [Member] | Commodity derivative instruments - current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative instruments in hedges, liabilities, at fair value	0	0	5,994
Designated as hedging instrument [Member] | Commodity contract [Member] | Other liabilities noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative instruments in hedges, liabilities, at fair value	0	0	534
Designated as hedging instrument [Member] | Interest rate swap [Member] | Other accrued liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative instruments in hedges, liabilities, at fair value	0	0	4,458
Not designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	330	1,950	4,556
Other derivatives not designated as hedging instruments liabilities at fair value	12,186	7,483	1,459
Not designated as hedging instrument [Member] | Commodity contract [Member] | Commodity derivative instruments - current assets [Member]
Derivatives, Fair Value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	81	1,447	4,313
Not designated as hedging instrument [Member] | Commodity contract [Member] | Other assets noncurrent [Member]
Derivatives, Fair Value [Line Items]
Other derivatives not designated as hedging instruments assets at fair value	249	503	243
Not designated as hedging instrument [Member] | Commodity contract [Member] | Commodity derivative instruments - current liabilities [Member]
Derivatives, Fair Value [Line Items]
Other derivatives not designated as hedging instruments liabilities at fair value	12,186	7,483	1,385
Not designated as hedging instrument [Member] | Commodity contract [Member] | Other liabilities noncurrent [Member]
Derivatives, Fair Value [Line Items]
Other derivatives not designated as hedging instruments liabilities at fair value	$ 0	$ 0	$ 74

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Long-term debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Long-term debt

Long-term debt

Centennial entered into a two year $125.0 million term loan agreement with a variable interest rate on March 31, 2014. In addition, borrowings outstanding that were classified as long-term debt under the Company’s and Centennial’s commercial paper programs totaled $283.5 million at March 31, 2014, compared to $153.9 million at December 31, 2013, respectively.

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Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingencies

Contingencies

The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. The Company had accrued liabilities of $31.4 million, $33.3 million and $29.5 million for contingencies, including litigation, production taxes, royalty claims and environmental matters, as of March 31, 2014 and 2013, and December 31, 2013, respectively, which include 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 seeking compensatory damages of $149.7 million. 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. CEM filed a petition with the New York Supreme Court to vacate the arbitration award in favor of LPP. On October 19, 2012, Centennial moved to intervene in the New York Supreme Court action to vacate the arbitration award and also filed a complaint with the New York Supreme Court seeking a declaration that LPP is not entitled to indemnification from Centennial under the guaranty for the arbitration award. The New York Supreme Court granted CEM's petition to vacate the arbitration award on November 20, 2012, and entered an order and judgment to that effect on June 5, 2013. LPP appealed the order and judgment and on February 20, 2014, the New York Supreme Court Appellate Division ruled the arbitration award was properly vacated. LPP filed a motion with the New York Court of Appeals for leave to appeal the decision of the New York Supreme Court Appellate Division. The motion remains pending. Due to the vacation of the arbitration award, the Company no longer believes the loss related to this matter to be probable and thus the liability that was previously recorded in 2011 was reversed in the fourth quarter of 2012. The effect of this was recorded in discontinued operations on the Consolidated Statement of Income. For more information regarding discontinued operations, see Note 9.

Construction MaterialsUntil 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. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.

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

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

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

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

Environmental matters

Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

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

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

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

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ 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 $1.7 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received an order reauthorizing the deferred accounting for the 12 months starting November 30, 2013.

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 of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $12.8 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.

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

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

Guarantees

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

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at March 31, 2014, expire in the years ranging from 2014 to 2015; however, Fidelity continues to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. The amount outstanding by Fidelity was $7.7 million and was reflected on the Consolidated Balance Sheet at March 31, 2014. 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 March 31, 2014, the fixed maximum amounts guaranteed under these agreements aggregated $48.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $26.8 million in 2014; $2.1 million in 2015; $700,000 in 2016; $600,000 in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at March 31, 2014. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At March 31, 2014, the fixed maximum amounts guaranteed under these letters of credit, aggregated $36.3 million. In 2014 and 2015, $7.0 million and $29.3 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at March 31, 2014.

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 March 31, 2014, the fixed maximum amount guaranteed under this agreement was $4.0 million and is scheduled to expire in 2016. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $700,000. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at March 31, 2014, 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 March 31, 2014.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of March 31, 2014, approximately $588.8 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

Variable interest entities

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

Dakota Prairie Refining, LLCOn February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are expected to be shared equally between WBI Energy and Calumet. The total project cost is currently estimated at $350 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75.0 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

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

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

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	22,996	$	10,793	$	4,774
Other current assets	1,135		—		26
Total current assets	24,131		10,793		4,800
Net property, plant and equipment	207,260		27,356		172,073
Total assets	$	231,391	$	38,149	$	176,873
LIABILITIES
Current liabilities:
Long-term debt due within one year	$	3,000	$	—	$	3,000
Accounts payable	16,103		10,948		8,904
Taxes payable	113		—		5
Accrued compensation	164		—		26
Other accrued liabilities	580		—		461
Total current liabilities	19,960		10,948		12,396
Long-term debt	72,000		—		72,000
Total liabilities	$	91,960	$	10,948	$	84,396

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

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

At March 31, 2014, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, at March 31, 2014, was $8.2 million.

XML

Derivative instruments (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Derivative instruments [Line Items]
Amount of unrealized gain (loss) on hedge at de-designation date to be reclassified into AOCI			$ 1,800,000
Amount of time remaining to transfer accumulated other comprehensive income to earnings	9 months
Cash flow hedge gain (loss) to be reclassified within twelve months from AOCI into earnings	(449,000)
Derivatives with credit-risk-related contingent feature in net liability position, aggregate fair value	12,200,000	7,500,000	12,400,000
Assets needed for immediate settlement aggregate fair value for cash flow hedging instruments	12,200,000	7,500,000	12,400,000
Oil swap and\or collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	2,700,000	2,900,000	2,800,000
Natural gas swap and\or collar [Member]
Derivative instruments [Line Items]
Derivative, nonmonetary notional amount	14,700,000	18,300,000	25,900,000
Interest rate swap [Member]
Derivative instruments [Line Items]
Derivative, notional amount			$ 40,000,000

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Earnings per common share (Details) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share [Abstract]
Weighted average common shares outstanding - basic	189,820	188,831
Effect of dilutive performance share awards	612	391
Weighted average common shares outstanding - diluted	190,432	189,222
Shares excluded from the calculation of diluted earnings per share	0	0

XML

Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Current assets:
Cash and cash equivalents	$ 83,700		$ 45,225		$ 74,149
Receivables, net	690,761		713,067		635,564
Inventories	301,332		282,391		334,872
Deferred income taxes	29,427		25,048		29,885
Commodity derivative instruments	81		1,447		5,936
Prepayments and other current assets	99,229		49,510		68,828
Total current assets	1,204,530		1,116,688		1,149,234
Investments	113,763		112,939		106,846
Property, plant and equipment	9,150,269		8,803,866		8,303,065
Less accumulated depreciation, depletion and amortization	3,954,442		3,872,487		3,678,535
Net property, plant and equipment	5,195,827		4,931,379		4,624,530
Deferred charges and other assets:
Goodwill	636,039	[1]	636,039	[1]	636,039	[1]
Other intangible assets, net	12,296		13,099		16,318
Other	246,394		251,188		295,215
Total deferred charges and other assets	894,729		900,326		947,572
Total assets	7,408,849		7,061,332		6,828,182
Current liabilities:
Short-term borrowings	0		11,500		37,500
Long-term debt due within one year	12,227		12,277		171,094
Accounts payable	399,935		404,961		375,942
Taxes payable	61,847		74,175		55,748
Dividends payable	33,980		33,737		32,744
Accrued compensation	40,016		69,661		31,382
Commodity derivative instruments	12,186		7,483		7,379
Other accrued liabilities	185,287		171,106		205,394
Total current liabilities	745,478		784,900		917,183
Long-term debt	2,093,605		1,842,286		1,618,569
Deferred credits and other liabilities:
Deferred income taxes	899,420		859,306		802,805
Other liabilities	720,542		718,938		814,643
Total deferred credits and other liabilities	1,619,962		1,578,244		1,617,448
Equity:
Preferred stocks	15,000		15,000		15,000
Common stockholders' equity:
Authorized - 500,000,000 shares, $1.00 par value. Shares issued - 191,838,720 at March 31, 2014, 189,369,450 at March 31, 2013 and 189,868,780 at December 31, 2013	191,839		189,869		189,369
Other paid-in-capital	1,110,221		1,056,996		1,038,970
Retained earnings	1,625,692		1,603,130		1,480,784
Accumulated other comprehensive loss	(37,538)		(38,205)		(56,615)
Treasury stock at cost - 538,921 shares	(3,626)		(3,626)		(3,626)
Total common stockholders' equity	2,886,588		2,808,164		2,648,882
Total stockholders' equity	2,901,588		2,823,164		2,663,882
Noncontrolling interest	48,216		32,738		11,100
Total equity	2,949,804		2,855,902		2,674,982
Total liabilities and equity	$ 7,408,849		$ 7,061,332		$ 6,828,182

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

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Accounts receivable and allowance for doubtful accounts

3 Months Ended

Mar. 31, 2014

Receivables [Abstract]

Accounts receivable and allowance for doubtful accounts

Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $22.6 million, $39.6 million and $36.4 million at March 31, 2014 and 2013, and December 31, 2013, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at March 31, 2014 and 2013, and December 31, 2013, was $10.9 million, $10.8 million and $10.1 million, respectively.

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Business segment data (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 1,042,853	$ 931,604
Intersegment operating revenues	0	0
Earnings on common stock	56,491	56,344
Regulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	491,541	424,124
Intersegment operating revenues	18,276	18,718
Earnings on common stock	42,645	44,673
Unregulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	551,312	507,480
Intersegment operating revenues	30,346	17,498
Earnings on common stock	14,197	11,671
Electric [Member] | Regulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	73,647	64,654
Intersegment operating revenues	0	0
Earnings on common stock	11,033	9,825
Natural gas distribution [Member] | Regulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	374,233	331,754
Intersegment operating revenues	0	0
Earnings on common stock	27,263	32,518
Pipeline and energy services [Member] | Regulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	43,661	27,716
Intersegment operating revenues	18,276	18,718
Earnings on common stock	4,349	2,330
Exploration and production [Member] | Unregulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	116,669	115,363
Intersegment operating revenues	20,867	9,812
Earnings on common stock	20,939	20,284
Construction materials and contracting [Member] | Unregulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	164,423	161,977
Intersegment operating revenues	4,017	4,294
Earnings on common stock	(23,574)	(20,582)
Construction services [Member] | Unregulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	269,892	229,806
Intersegment operating revenues	3,738	1,574
Earnings on common stock	16,568	11,664
Other [Member] | Unregulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues	328	334
Intersegment operating revenues	1,724	1,818
Earnings on common stock	264	305
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0	0
Intersegment operating revenues	(48,622)	(36,216)
Earnings on common stock	$ (351)	$ 0

XML

Subsequent event

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Subsequent events [Text Block]

Subsequent Events

Centennial entered into a two year $125.0 million term loan agreement with a variable interest rate on April 2, 2014.

The Company entered into a $150.0 million note purchase agreement on January 28, 2014. On April 15, 2014, the Company issued $50.0 million of Senior Notes with a due date of April 15, 2044, at an interest rate of 5.2 percent. The remaining $100.0 million of Senior Notes under the agreement will be issued on July 15, 2014, with due dates ranging from July 2024 to July 2026 at a weighted average interest rate of 4.3 percent.

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Contingencies Commitment and Contingencies Disclosure (Tables)

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Limited liability project reflected on consolidated balance sheet

The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets were as follows:

	March 31, 2014		March 31, 2013		December 31, 2013
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	22,996	$	10,793	$	4,774
Other current assets	1,135		—		26
Total current assets	24,131		10,793		4,800
Net property, plant and equipment	207,260		27,356		172,073
Total assets	$	231,391	$	38,149	$	176,873
LIABILITIES
Current liabilities:
Long-term debt due within one year	$	3,000	$	—	$	3,000
Accounts payable	16,103		10,948		8,904
Taxes payable	113		—		5
Accrued compensation	164		—		26
Other accrued liabilities	580		—		461
Total current liabilities	19,960		10,948		12,396
Long-term debt	72,000		—		72,000
Total liabilities	$	91,960	$	10,948	$	84,396

XML

Fair value measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair value measurements

Fair value measurements

The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $63.3 million, $53.3 million and $62.4 million, as of March 31, 2014 and 2013, and December 31, 2013, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were $900,000 and $4.4 million for the three months ended March 31, 2014 and 2013, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

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

March 31, 2014	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	7,943	$	63	$	(17	)	$	7,989
U.S. Treasury securities	2,069		9		—			2,078
Total	$	10,012	$	72	$	(17	)	$	10,067

March 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,749	$	133	$	(3	)	$	8,879
U.S. Treasury securities	1,301		39		—			1,340
Total	$	10,050	$	172	$	(3	)	$	10,219

December 31, 2013	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(In thousands)
Mortgage-backed securities	$	8,151	$	69	$	(27	)	$	8,193
U.S. Treasury securities	1,906		15		(4		)	1,917
Total	$	10,057	$	84	$	(31	)	$	10,110

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

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

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

The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

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

The estimated fair value of the Company's Level 2 commodity derivative instruments 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 also 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 also 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 months ended March 31, 2014 and 2013, there were no transfers between Levels 1 and 2.

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

	Fair Value Measurements at March 31, 2014, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2014
	(In thousands)
Assets:
Money market funds	$	—	$	20,267	$	—	$	20,267
Insurance contract*	—		63,269		—		63,269
Available-for-sale securities:
Mortgage-backed securities	—		7,989		—		7,989
U.S. Treasury securities	—		2,078		—		2,078
Commodity derivative instruments	—		330		—		330
Total assets measured at fair value	$	—	$	93,933	$	—	$	93,933
Liabilities:
Commodity derivative instruments	$	—	$	12,186	$	—	$	12,186
Total liabilities measured at fair value	$	—	$	12,186	$	—	$	12,186

*  The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 27 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 16 percent in fixed-income investments.

	Fair Value Measurements at March 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at March 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	31,281	$	—	$	31,281
Insurance contract*	—		53,334		—		53,334
Available-for-sale securities:
Mortgage-backed securities	—		8,879		—		8,879
U.S. Treasury securities	—		1,340		—		1,340
Commodity derivative instruments	—		6,179		—		6,179
Total assets measured at fair value	$	—	$	101,013	$	—	$	101,013
Liabilities:
Commodity derivative instruments	$	—	$	7,987	$	—	$	7,987
Interest rate derivative instruments	—		4,458		—		4,458
Total liabilities measured at fair value	$	—	$	12,445	$	—	$	12,445

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

	Fair Value Measurements at December 31, 2013, Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs  (Level 3)		Balance at December 31, 2013
	(In thousands)
Assets:
Money market funds	$	—	$	19,227	$	—	$	19,227
Insurance contract*	—		62,370		—		62,370
Available-for-sale securities:
Mortgage-backed securities	—		8,193		—		8,193
U.S. Treasury securities	—		1,917		—		1,917
Commodity derivative instruments	—		1,950		—		1,950
Total assets measured at fair value	$	—	$	93,657	$	—	$	93,657
Liabilities:
Commodity derivative instruments	$	—	$	7,483	$	—	$	7,483
Total liabilities measured at fair value	$	—	$	7,483	$	—	$	7,483

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

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

	Carrying Amount		Fair Value
	(In thousands)
Long-term debt at March 31, 2014	$	2,105,832	$	2,186,839
Long-term debt at March 31, 2013	$	1,789,663	$	1,925,859
Long-term debt at December 31, 2013	$	1,854,563	$	1,912,590

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